bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Tube Curvature on Temperature Separation Efficiency of Ranque-Hilsch Vortex Tube
Authors: Khan Shahzaib Yousuf , Allauddin Usman , Hasani Syed Muhammad Fakhir , Khan Rashid , Arsalan Muhammad 
Published: February 2022

Abstract
Vortex tube that splits a single compressed gas stream into two separate hot and cold streams had been successfully used for spot cooling, and refrigeration. Significant temperature gradient exists between hot and cold stream ends that could be utilized for power generation using thermo-electric generators. Distance between hot and cold ends could be vital for small inaccessible down-hole well locations which may require the use of curved vortex tubes. Efficiency of vortex tube depends on temperature difference between hot and cold ends. In this work, effects of tube curvature on temperature separation efficiency are investigated through numerical simulations. Numerical models of straight and curved vortex tubes are developed in a commercial computational fluid dynamics package Ansys-fluent®. For the curved tube, multiple curvature angles are used to analyze the effects of curvature on velocity and temperature fields inside the vortex tube. The standard κ − ε turbulence model is used to model three-dimensional turbulence. The cold stream mass fraction is varied by controlling hot exit pressure. The numerical results for 110° curved vortex tube are validated through published experimental data and are found to be in good agreement. It is found that the curvature has affirmative results on temperature separation efficiency as compared to straight tube. This is mainly due to the energy separation phenomenon governed by the multi-circulation loop extension and multiple vortex formation in curved vortex tubes. Curvature angles of 180° and 270° have similar effects on the vortex tube where the maximum ΔTc obtained is 15.7 K which is about 5.3% higher than the straight vortex tube. The temperature separation ΔThc values for curved tubes are comparable with straight tube, the maximum being 25.2 K for the 150° curved vortex tube which is about 0.8 per higher than the straight tube. The temperature separation efficiency for curved vortex tubes with curvature angles larger than 150° is found to be higher than straigt tube, the maximum value being 8.7% for the 270° curved tube. A profound investigation of the effects of curvature on energy separation phenomenon in a vortex tube had been lacking and this research attempts to fill that gap. This novel work is expected to provide insight into the energy separation mechanisms in vortex tubes and lead the way to their use in thermo-electric power generation.
Application of Phenolic Resin Crosslinked Polymer Gel in Fractured-Vuggy Carbonate Reservoir with High Temperature and High Salinity
Authors: Wu Weipeng , Hou Jirui , Qu Ming , Wu Wenming , Zhang Wei , Wen Yuchen , Liang Tuo , Xiao Lixiao 
Published: February 2022

Abstract
As a special unconventional reservoir, the high temperature and high salinity of fracture-vuggy carbonate reservoirs has been confining the advance of EOR technology. Take water plugging as an example, the majority of plugging agents currently do not have temperature and salt resistance at the same time. Therefore, a novel Phenolic Resin Crosslinked Polymer Gel (NPRG) which has excellent resistant to high temperature (140°) and ultra-high salinity (240000mg/L) reservoirs is going to be developed. In this paper, methenamine, hydroquinone, thiourea, cobalt chloride hexahydrate (CCH) are synthesized by certain mass ratio. Besides, rotational rheometer, SEM were used for characterization before and after gelation, plugging performance of gel was measured using cubic fractured core. The research found that, CCH can provide more crosslink points for the 3D mesh structure of bulk gel system. Therefore, the period of dehydration of gel microstructure was extended. The initial viscosity was 77.1mpa·s when this bulk gel system achieved its optimal concentration ratio, besides, the dehydration rate of this bulk gel system is only 5% within 30 days and its strength can be stabilized at H-I level within 150 days. The NPRG also has a satisfactory shear resistance performance and a better erosion resistance. Additionally, result of core flooding experiment showed that NPRG achieve a plugging rate of 90% and has little damage to the substrate. Finally, the success of laboratory experiments and pilot tests indicates that NPRG has certain application potential in fracture-vuggy carbonate reservoirs where fractures are dominantly developed.
Cost Engineering Software: Value Based Management of Oil and Gas Assets in All Investment Process Stages
Authors: Pashkevich Lev , Gordeeva Daria , Skudar Oleg , Kashafutdinova Aliya , Lyasovich Denis , Ulyaschenko Vladislav 
Published: February 2022

Abstract
This paper gives an overview of Gazprom Neft's strategic goals and describes how industry benchmarking helps in achieving them. In particular, we offer a general description of Gazprom Neft's cost management processes with a detailed focus on two of them: baseline cost and reserve estimate, and project cost monitoring and control. The digital landscape of cost engineering is also described, which is represented by three interrelated cost estimation tools, and a software product that allows you to manage capital expenditures at subsequent stages — to monitor and control the cost of the project. The cost engineering software products are unique solutions for the industry, and their features are described in this paper.
Project Gradient - A Tool for Comparative Analysis and Potential Search
Authors: Bazyleva Nafisa , Mozhchil Artem , Pashkevich Lev , Yanina Irina , Skudar Oleg , Pislegin Mikhail , Gerasimov Fedor , Kozlovskii Pavel 
Published: February 2022

Annotation
The new strategy of our Company is aimed at increasing efficiency in the growth of reserves and production of hydrocarbons by maximizing the created value of each barrel in any scenario of the development of the outside world. The company aims to become a benchmark for players in the Russian and global industry in the field of safety, efficiency and manufacturability by 2030 - a global industry benchmark.
Now being adopted capacity-based performance management is a set of management processes (planning, organization of implementation, control and analysis) that allow enterprise management to determine goals in the field of improving the efficiency of production and business processes and manage their achievement. This approach is based on a comparison of performance indicators by areas of activity with the best results achieved within the Company and by world leaders in the industry, with further development and implementation of measures aimed at reducing gaps.
A tool is needed to search for directions with great potential and to correctly assess the potential. The task of the tool is to find a benchmark, assess the potential in each area (metric) and help production units with the search for activities that will allow this potential to be realized.
The developed tool will consist of modules in accordance with the stages of deep technical benchmarking by processes and cost items by assets and industry, including: Automated collection of current metricsIdentification of reference metricsAssessment of potentialIdentification of levers and hypotheses generatingMonitoring of the declared technical metrics achievement
As a result of the Gradient project, it is expected: Improving the quality of the formation of hypotheses about potential due to a targeted search for levers of its implementation.Expansion of the collection and analysis perimeter of data on gas and gas condensate assets.Creation of a unified cost decomposition methodology and OPEX database for the entire company with the ability to anonymously dataview for all assets.Improving the projects and business efficiency cases through competent identification and application of best practices at the conceptual design stage.Improved quality and speed of decision making through advanced analytics and modeling.The dissemination of the platform based on anonymous data will allow all companies in the industry to regularly conduct internal analysis and look for development potential.
Mitigation of Geomechanical Risks for Long Term CO2 Geological Storage
Authors: Tan Chee Phuat , Ali Siti Syareena , Yakup M Hamzi , Mustafa M Azlan , Chidambaram Prasanna , Mazeli Abdul Hakim , Hanifah M Azri 
Published: February 2022

Abstract
Carbon dioxide (CO2) capture and geological storage is one of the best alternative methods of produced CO2 disposal rather than venting it into the atmosphere. However, there are numerous geomechanical challenges and risks associated with CO2 injection and geological storage that are required to be addressed. The key challenges include delineating the geological seal barrier and maintaining the seal integrity throughout the injection operation and storage life.
The assessment of geomechanical-related challenges and risks to manage CO2 containment and mitigate leakage risks require a coupled geomechanical study that needs to be conducted as part of feasibility evaluation of injecting and storing CO2 in a field. In the geomechanics-dynamic coupled modelling, at selected stress steps the reservoir model passed data including pressure, CO2 concentration within the plume, water saturation and temperature to the geomechanical model. Changes in stresses, rock mechanical and rock petrophysical properties based on laboratory CO2-rock interaction test data, displacements, strains and deformations were computed by the geomechanical model using the data from the reservoir model. Updated petrophysical properties such as permeability and porosity were passed by geomechanical model back to the reservoir model and used in the next dynamic simulation step.
The coupled geomechanical modelling assessed CO2 leakage risk associated with fault re-activation, failure of cap rock, CO2-rock interaction, and cooling of injected CO2 on caprock and reservoir rock. Axial loading on completions due to reservoir compaction could cause buckling collapse and/or cement failure. Fault re-activation was based on induced fault plastic shear strain throughout the injection programme which may pose risk of CO2 leakage. The evaluation of induced plastic shear strain and failure state of caprock, effect of CO2 interaction and cooling on the caprock and reservoir rock integrity, and compaction and associated subsidence were also evaluated. Recommendations from geomechanical perspective can subsequently be developed from the results and findings for the CO2 injection programme and storage operation.
Sustainable and Eco-Friendly Drilling Fluid Additives Development
Authors: Ramasamy Jothibasu , Arfaj Mohammad. K. 
Published: February 2022

Abstract
Drilling fluid is an inseparable component of drilling oil and gas wells and circulated from the day of spudding to the day of completing a well. Drilling fluid consists of a variety of chemicals to provide various properties to drilling fluid such as viscosity, fluid loss control, emulsion stability, lubricity, etc. Developing chemicals that are eco-friendly and sustainable to provide the above-mentioned properties to drilling fluid is a significant step forward taken towards sustainability and reducing carbon footprint besides suitability for aquifers and offshore environments. Several fatty acid-based products play a crucial role in drilling fluids additives development as fatty acids offer eco-friendly and bio-degradable properties. Triglycerides present in vegetable oil is a potential source of fatty acids and their derivatives. Used cooking oil (UCO) provides a perpetual and sustainable source of raw material for various types of eco-friendly additives development. Used cooking oil is subjected to simple chemical modification of base hydrolysis process and mixture of fatty acids have been obtained after completing a sequence of clean-up process of reaction mixture. The fatty acids obtained are eco-friendly, bio-degradable and non-toxic. Due to technical, economic and environmental benefits, we have conducted several research projects to develop various chemicals from used cooking oil for oil and gas field applications. Fatty acid-based products mainly used in drilling fluids as lubricants to reduce torque and drag for water-based mud. In case of oil-based mud systems, fatty acid derived products are used as emulsifiers, wetting agents and rheology modifiers. However, these products have been either mixture of fatty acids and their derivatives or only derivatives of fatty acids. In our study, we have used the mixture of fatty acids obtained from chemical conversion of UCO for applications as lubricant for water-based mud and emulsifier and rheology modifier for invert emulsion oil-based mud systems. This paper describes the chemicals process for converting used cooking oil to fatty acids by base hydrolysis reaction in the first section. Application of synthesized fatty acids for water-based and oil-based mud formulation as lubricants, emulsifiers and rheology modifiers have been discussed in the second part of the paper.
Multi-Purpose Wellhead
Authors: Garcia Javier 
Published: February 2022

Abstract
The conventional oil drilling process includes the drilling of a well, a reservoir having pressure and a mixture of oil/gas/water flowing out of the ground. Eventually as a well gets older and the reservoir pressured reduces, some form of artificial lift becomes necessary. For wells producing a significant amount of gas, either gas lift or a related method (plunger lift for example) tends to be the sensible solution. Ultimately, once the reservoir pressure and production levels have depleted substantially, rod pumping becomes relevant.
Each production method requires a specific surface piping and valving arrangement to allow for the wellbore fluids to flow with minimum restriction as well as fluid injection as applicable. Following safety and operational protocols established by each operator, the surface arrangement should be inclusive of multiple barriers to shut down production should the need arise. Redundancy becomes a necessity to ensure compliance with safety regulations while protecting the assets.
Adapting the wellhead stack to the production method requires major interventions with the associated cost and deferred production. Logistic and planning can be critical for smooth modification of the wellhead stack especially when several wells are involved.
In this context, a universal piece of equipment engineered for compatibility with all production stages of the well can add value to the operation by eliminating wellhead stack modifications and minimizing deferred production through the well life cycle.
An Efficient Technology and Solution Well Operation by Maintain Well Integrity in Offshore Field
Authors: Saleppang Kila Edyos Wyndu , Firmansyah Dadang 
Published: February 2022

Abstract
The point of well integrity is how to produce hydrocarbon from the source (well) to surface safely. The main goal of this paper is to keep well in operation due to gas supply and demand in the field, identify tubing/ annulus communication, mitigate any excessive annulus pressure, and corrective action of tubing casing leaks refer to industrial code and Well Integrity Management System (WIMS).
One of the wells in "P" platform, namely "W" well has found a leak between production tubing and production casing ("A" annulus) and no any excessive presure from "B" & "C" annulus in this case. There is no way to shut-in the well due to gas supply and demand in our field and the well must be operate safely by conduct annulus pressure monitoring, pressure limit calculation, regular bleed-off program, and modify surface facilities.
Pressure limit is calculated by determine MAASP and MOASP to ensure working pressure and bleed-off program are managed. Annulus pressure bleed-down program is one of mitigation action to manage excessive pressure in annulus. We have provided technical recommendation, specify mitigate engineering solution to reduce risks, and modify surface facilities to keep wells in operation. Based on jobs result, we have done to operate all wells safely with efficient technology, deliver fluid from 3 ½" production tubing to surface facilities, perform cost optimization, and minimize production loss. We have also performed to manage and maintain annulus casing pressure successfully related to well integrity implementation. Furthermore, In this case, there is no serious hazard during these conditions in offshore field.
The paper will share success story, method, and detail procedure to keep well operation by maintain annulus casing pressure in offshore field. We have done this method by efficient technology/ solution with lower operating & construction cost and there is no production loss during operation. We confidence this method can be applied successfully not only for our field, but also other business/ operating units which has similar conditions.
Evaluating the Impact of Rock Hardness and Roughness on Acid Fracturing Conductivity
Authors: Hassan Amjed , Tariq Zeeshan , Al-Abdrabalnabi Ridha , Saleh Aljawad Murtada , Mahmoud Mohamed 
Published: February 2022

Abstract
Different techniques are used to increase the hydrocarbon production from carbonate reservoirs; the common approach is applying acid fracturing. Channels and rough fracture surfaces can be created due to the acid injection at high pressure. The rock properties and mineralogy will have a significant impact on the treatment performance. This paper presents the impact of rock hardness and roughness on the fracture conductivity during HCl and GLDA chelating agent as acid fracturing fluids. Silurian dolomite, Indiana limestone, and Austin chalk were used in this work. Smooth initial fracture surfaces were created by cutting the rock samples into two parts. Six coreflooding experiments were conducted by injecting the acid fluids into the carbonate samples. The rock strength and the surface roughness were measured using Brinell hardness tester and Kruss high-resolution surface analyzer respectively. The results showed that the fracture conductivity was controlled by the type of injected fluids and the rock hardness and roughness. Strong acids such as HCl can produce higher conductivity compared to chelating agent solutions, due to the higher created surface roughness. Significant increases were observed in the fracture conductivity for chalk and limestone rocks when treated with GLDA, while a slight increase was achieved for the dolomite conductivity. Overall, this work can help in improving the performance of acid fracturing treatments by providing a better section for the acid type based on the rock hardness and roughness.
Rheological Optimization of CO2 Foamed Chelating Stimulation Fluids at High-Pressure, High-Temperature, and Salinity
Authors: BinGhanim Ahmed , Al-Darweesh Jawad , Aljawad Murtada S. , Zhou Xianmin , Kamal Muhammad S. , AlYousif Zuhair , Mahmoud Mohamed 
Published: February 2022

Abstract
Foamed acidic fluids have been utilized in the industry for enhanced oil recovery and fracturing applications due to their various advantages. Flowback enhancement, recovery of treatment fluids, and reduction of overall water consumption per operation are examples of these advantages. This study examines the utilization of a chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA) in N2 and CO2 foamed fluids, which enhances the stability of foamed acidic fluids, lowers corrosion tendency, and is environmentally friendly.
A modified high pressure and high temperature (HPHT) foam rheometer, and foam analyzer at ambient conditions, are used to test the acidic foamed fluids prepared in produced water using N2 and CO2. A screened out Alkyl diamine derivative surfactant has been tested at 212-300 °F and 1000 psi with and without GLDA. The effect of corrosion inhibitor addition on viscosity and foam quality is also investigated. Viscosity and foam quality measurements were done at increasing shear rates from 500 1/s up to 2000 1/s.
Results showed that GLDA enhances the foamed fluid viscosity and stability. Resulted viscosities were in the range of 5 cP at higher shear rates to 25 cP in the lower shear rates region. Viscosity, in general, is lowered by higher shear rates, but foam quality is not affected. Fluid systems with a corrosion inhibitor also resulted in lower viscosities. The most stable and relatively higher viscosity values resulted from the 1 wt.% surfactant concentration with the addition of 15 wt.% GLDA and no corrosion inhibitor. Ambient conditions foam analyzer results showed higher foam height and half-life values of 182.8 mm and 16.5 minutes respectively when foaimg using N2 compared to 77.4 mm and 2.16 minutes when foamed with CO2. The addition of corrosion inhibitor showed significant negative impact in all cases, but least on the half-life of the CO2 foamed fluid. The rheology study provided did not consider the addition of thickeners which could be further investigated.
This study covers the novel utilization of a chelating agent as an additive in CO2 and N2 acidic foamed fluids at harsh conditions. Furthermore, the fluid systems tested can be investigated and utilized as reliable stimulation fluid systems at temperatures up to 300 °F.
A Novel Foamed Acid System Stabilized by Composite Material for Fracturing Applications
Authors: Alarawi Abeer , Al Harbi Bader , Busaleh Ahmed 
Published: February 2022

Abstract
Carbonate reservoirs hold 60% of the world's oil and 40% of the gas. Therefore, developing high-impact and innovative technologies for well stimulation, such as foamed acid fracturing fluids, is essential for restoring well productivity and enhancing commercial productivity for carbonate reservoirs. Acid fracturing treatment is associated with reactivity control, fluid loss control, and conductivity generation challenges. For overcoming some drawbacks associated with conventional acid fracturing, foamed acid fluid is applied to enhance retardation, reduce water consumption, improve acid diversion, remove water or emulsion blocks, and improve conductivity generation. In this study, a unique foamed acid system stabilized by composite material was studied to develop fracturing fluid at 275-350 °F. In addition, the foam stability, rheology, and morphology characteristics were investigated using several characterization tools at 275-350 °F.
The composite material comprises nanosheet (NS), and surfactant (SURF) were added to either a pure-acid or acid system that contains several additives for developing stable NS/SURF-based foamed acid fluid. To evaluate foam rheological properties and thermal stability at dynamic conditions, foam loop rheometer experiments were conducted at 275-350 °F, 1050 psi, and 70 % N2 quality. A high-resolution optical microscope was also utilized to observe foam texture morphology and further assess foam stability. In addition, foam-decaying time was observed by determining the foam-half-life-time (foam volume altering as a function of time).
The static and dynamic results illustrated that foamed acid fluid stability and thermal adaptability were improved after adding composite material at 275-350 °F. The viscosity of foamed acid increased by double and its viscosity was higher than 45 cP at a shear rate of 300 S-1 and 350 °F. In addition, the foam-structure of NS/SURF-based foamed acid displayed a small hexagonal bubbles size, which positively affected the stability of foam to reach up to three hours at 300 °F. In contrast, the stability of pure foamed acid was one hour. This result is attributed to the adsorption of composite material at the liquid-gas interface layer that enhances the mechanical strength of the foam-layer (lamellae film) and provides a more robust barrier between the gas bubbles and liquid phase, resulting in delaying the coalescence of the bubbles. The developed NS/SURF-based foamed acid possesses several advantages over the conventional acid fracturing fluids: long stability, adequate viscosity (obtained without adding gelling agent), low water consumption, and high efficiency at 275-350 °F.