bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mitochondria Transfer to CD4+ T Cells May Alleviate Rheumatoid Arthritis by Suppressing Pro-Inflammatory Cytokine Production
Authors: Giwa Rocky , Brestoff Jonathan R. 
Published: March 2022

Abstract
CD4+ T cells contribute to the pathogenesis of autoimmune diseases such as rheumatoid arthritis (RA). These cells infiltrate the joints of RA patients and produce cytokines, including Tumor necrosis factor (TNF)-α, that drive joint inflammation and bone destruction. Although biologic therapeutics targeting T cells and TNF-α have benefited patients suffering from RA, some patients are refractory to these therapies, develop antibodies that neutralize these biologics, or develop undesirable side effects. Recent studies indicate that CD4+ T cell cytokine production is regulated in part by specific metabolic modules, suggesting that immunometabolic pathways could represent a novel therapeutic strategy for T cell-mediated diseases such as RA. Wu et al. (2021) demonstrate that mitochondrial function is impaired in CD4+ T cells from RA patients, leading to reduced levels of various citric acid cycle metabolites (e.g., aspartate) that regulate TNF-α production. Treatment of RA-associated T cells with purified mitochondria was sufficient to restore these metabolic defects, limit production of numerous pro-inflammatory cytokines such as TNF-α and IL-17A, and reduce the development of RA-like disease in a humanized mouse model. These data suggest that T cells can be metabolically "re-engineered" ex vivo with exogenous mitochondria and that this mitochondria transfer approach confers anti-inflammatory properties that may reduce disease severity in RA and possibly other rheumatologic diseases. Increasing our understanding of how intercellular mitochondria transfer occurs may identify novel biological pathways that can be targeted therapeutically or harnessed to support cell engineering.
Recommendations from the ICM-VTE: General
Authors:   The ICM-VTE General Delegates
Published: March 2022

Update
This article was updated on June 17, 2022 because of a previous error. On page 33, in the section entitled “17 - Does administration of tranexamic acid (TXA) to patients undergoing orthopaedic procedures increase the risk of subsequent VTE?”, and in the note on page 161, the name “Armin Arish” now reads “Armin Arshi.”
An erratum has been published: J Bone Joint Surg Am. 2022 Aug 3;104(15):e69.
Extended Polymer Injectivity Test in a Medium Viscosity Sandstone Oil Reservoir, Sultanate of Oman
Authors: Al Amri Badar , Setiawan Hari Sudono , Akbar Muhammad Rifki , Al Rashdi Yaqoob , Al Nabhani Fahad 
Published: March 2022

Abstract
This is an extended polymer-injectivity-test where the main objectives are to prove that polymer solution can be injected at acceptable conditions and injectivity can be sustained for a considerable time period. Other objectives include determining the need for certain protective additives, evaluating the possibility of oil gain in producing wells around the test injector and providing some input to the process of flood pattern optimization.
A nine-month's polymer injectivity test has been implemented in HRD sandstone reservoir (Karim Small Fields’ Cluster, Sultanate of Oman) as part of the ongoing chemical flood evaluation. Selected polymer and desired concentrations are based on extensive laboratory test programs. The subject reservoir has been producing for over thirty years, mostly on primary conditions but with a successful waterflood (using inverted, irregular seven-spot patterns) during the last seven years that is still ongoing. Reservoir oil is highly under-saturated, 29° API gravity with initial viscosity of about 15 cP. Average depth is 1,200 mMD and absolute permeability is in the range of 250-500 mD. Chemical flooding is selected as the appropriate EOR method and is currently being evaluated in order to determine the optimum process design that can provide maximum incremental oil recovery over the ongoing waterflood.
Preliminary results from the polymer injectivity test confirm that injection rate of about 150 m3/d can be sustained at maximum surface injection pressure of around 4,000 kPa. Polymer break-through (at low traces) is observed in two of the six surrounding producing wells. Oil gain observed in surrounding producing wells is in the range of 0 - 5 m3/d/well which is lower than the values predicted by the simulation model.
The reasons leading to low oil gain and general reservoir behavior within the injectivity pattern are discussed in the paper. The discussed reasons and behavior are essential design aspects of a potential chemical-flooding pilot that can be implemented for analogous fields.
A Real Time Geomechanics Drilling Mud Window to Enhance Drilling Efficiency
Authors: Alawami Mohammed , Al-Yami Abdullah , Gharbi Salem , Al-Rubaii Mohammed 
Published: March 2022

Abstract
Enhancing the efficiency in drilling operations can lead to significant reduction in the overall costs of wells construction. Efficiency is generally achieved by maximizing drilling rate of penetration (ROP) while minimizing non-productive time (NPT) such as loss of circulation, well control and stuck pipe incidents. Reducing the uncertainties associated with subsurface formations, especially formation stresses around the wellbore, is one key aspect to decreasing the frequency of NPT incidents.
Understanding wellbore stresses and the mechanical properties of subsurface formations is essential to optimize drilling surface parameters and drilling fluids properties to ultimately maximize drilling ROP and minimize NPT. Determination of the geomechanics drilling mud window in real time allows drilling operations to proactively prevent fractures and/or formation instabilities. The availability of the mud window in real time will enhance the rig reaction time to any abnormalities experienced while drilling to maintain bottomhole pressure (BHP) consistently within the window.
The drilling mud window is constrained by a maximum and a minimum mud weight (MW) boundaries. The lower limit represents the stability gradient and the upper limit represents the fracture gradient. Drilling with a MW below the lower limit may cause formation instabilities such as caving and swelling that could lead to more severe consequences such as stuck pipes. Exceeding the upper limit MW may induce formation fractures that lead to loss of circulation that increases the risks of well control incidents.
The developed model automatically and continuously calculates formation mechanical properties such as Young's modulus and Poisson's ratio using sonic logging while drilling (LWD) data. Based on formation specific correlations, the model then determines the in-situ stresses, induced stresses, and principle stresses. The fracture and stability gradients can be determined and converted to a MW for easier communication with the drilling crew. The maximum and minimum MWs are displayed as curves in real time that allows immediate adjustments to drilling parameters and/or drilling fluid properties.
Geomechanics studies that contain the mud window are usually conducted pre-drilling using offset wells data, and these studies are often updated post-drilling only, which does not reduce the uncertainties associated with them. A real time model maintains the window relevant and up to date with the new data generated from the well.
A Comparative Analysis for Optimal Fracture Design Between the Crest and Flank Wells. Examples from Saih Rawl, Oman Tight Gas Field
Authors: Al Hinai Adnan Saif , Abdelazim Mohamed , Al Bahri Khalfan , Al Suleimani Ahmed Abdullah , Nunez Alvaro Javier , Al Shekaili Aadil Salim 
Published: March 2022

Abstract
Saih Rawl gas is located in the South Oman Salt Basin. There are two main formations targeted for gas production; Barik & Miqrat Formations. These formations are tight and exhibit low permeability. In order to enhance gas production, these formations have to be hydraulically stimulated.
The main objectives of this paper is to demonstrate the petrophysical properties of the hydraulically fractured zones. Assess gas flow contribution thru the individual zones measured by production logging and comparing with the amount of proppant placed in the formation. In addition, the paper discusses reservoir properties and characteristics obtained from logging, post stimulation operations results and post stimulation gas production. The paper discusses 20 wells; 10 from the crest and 10 from the flank. The two formations Barik and Miqrat cover approximately 17 sub reservoir units.
The total overall placement ratio is 95% and 78% for the crest and flank respectively with 156 hydraulic stimulation stages. It was observed that five sub reservoir units proved to be challenging to place the desired proppant. The maximum operating pressure is reached before achieving the desired proppant concentration leading to a screen out; concentrations of 2 – 3 pounds per gallon. Petrophysical evaluation of porosity and permeability cross plots showed a linear relationship in the wells in the crest. While there was no clear relationship was seen in the flank. Radioactive tracers used are to understand if there is any proppant propergation into the higher or lower zones. Not all the five challenging sub reservoir units showed propergation to other units. The wells located in the crest showed a better production rate as compared to the flank.
The paper highlights the importance of the using petrophysical evaluation to optimize hydraulic fracturing design for successful operations.
Feasibility of Ion-Modified Water for Low Salinity Water Flooding: A Case Study for Ultra-High-Salinity Carbonate Reservoir in Akanskoe Oilfield Tatarstan, Russia
Authors: Varfolomeev Mikhail , Rezaei Koochi Mojtaba , Yuan Chengdong , Khayrtdinov Ruslan , Mustafin Aidar , Glukhov Mikhail , Kadyrov Rail , Sudakov Vladislav , Usmanov Sergey 
Published: March 2022

Abstract
This paper presents the feasibility of the application of ion-modified water for enhanced oil recovery (EOR) in low permeable carbonate reservoir with ultra-high salinity of more than 220000 mg/L. Influence of different ions on wettability alteration, interfacial tension (IFT), scale tendency, recovery factor, and water injectivity was investigated. For choosing the optimized injection-water sequence, different types of water (formation water, distilled water, fresh water, and ion-modified water) were used. First, their effects on wettability alteration by measuring contact angle (oil-water-rock) and IFT were evaluated. Then, core flooding experiments were carried out to investigate how different injection sequence affects the oil recovery and injectivity. Furthermore, the scale tendency of different salts was simulated. The results showed that Mg2+ is the most effective ion. The addition of Mg2+ can fast change the oil-wet (130°) carbonate rock to water-wet (29°). The presence of mono-valent ions has negative effects on the effectiveness of Mg2+ on wettability alteration. Also, the presence of Mg2+ in fresh water and distilled water can reduce oil-water IFT two times lower. Core flooding experiments showed that after fresh water or formation water flooding (until 100% water cut), the sequent diluted formation water (diluted 10 times) yielded incremental oil recovery of about 3-5%, while the Mg2+ modified water obtained incremental oil recovery of about 8-18%. This indicates that Mg2+ modified water has a promising prospect in EOR in carbonate reservoirs.
A comprehensive analysis combining contact angle measurements, IFT testing, and core flooding experiments indicates that the high efficiency of Mg2+ modified fresh water for EOR mainly benefits from its strong wettability alteration ability. In addition, it was found that the existence of Mg2+ and SO42− can reduce the tendency of precipitation of salts compared with using only fresh water or diluted formation water. This work proves that ion-modified water by adding Mg2+ to fresh water can be an effective, low cost and environment-friendly EOR method for low-permeability carbonate reservoirs with ultra-high salinity. Simultaneously, this research provides some basic data that can help to enrich the theory for developing low salinity water flooding for EOR.
Benefits of New Digital Solution and Workflow Applied to Fast Track Subsea Development
Authors: Romero Mora Bruno Jesus , Ioannilli Beatrice , Stobart Sam , Gassert Michael , Castellito Tommaso , Sartirana Stefano , Calabrese Vito , Belleza Arturo , Ballotta Jimmy , Duclocher Fabien , Citi Gianfederico , Knight Darrell , Lien Jostein 
Published: March 2022

Abstract
An Eni initiative Fast 3Digital Subsea was made to identify opportunities for improving Company's Subsea developments in terms of time, quality and cost by applying a new way of working and implementing a new digital tool, the FieldAP/Fieldtwin platform (by FutureOn).
The purpose of this paper is to present the results of the comparison made between the conventional way of working and the application of the Fast 3Digital Subsea on subsea tieback projects. Data was collected and analysed for a project using the Fast 3Digital Subsea and the results showed the following key success benefits for Eni projects: time saving, cost reduction and improvement in engineering, quality and safety.
The benefits listed above were proved during the engineering phase of the project, however the Fast 3Digital Subsea is expected to lead to similar improvements for the future phases of the projects such as installation, commissioning, maintenance and operation. From a Project point of view, the digital solution is expected to lead to minimum time savings of between 1-2 months from discovery to First Oil.
This 1-2 months saving are expected mainly in projects where the critical path is represented by subsea items / flowlines that could benefit from an early procurement, in particular tie-backs to existing facilities (FPSO, FPU, and Onshore Plants).
For this paper, an Eni project was chosen as the base case and the impacts on project schedule, cost, quality, and discipline collaboration during the engineering, feasibility and FEED activities were evaluated.
The Fast 3Digital Subsea allowed engineers to evaluate multiple scenarios more effectively, increased the quality on the project documentation, allowed to select the optimum field layout configuration at an early stage and to quickly prepare an ITT package. All of the above, showed an average time saving of approximately 30% on field layout preparation, therefore cost saving compared to the conventional way of working were realised.
Another significant time saving obtained by implementing a Fast 3Digital Subsea approach was during creating of overall deliverables with time saving of nearly 60% during Pre-FEED activities.
All of time savings are broken down in activities and are described in the results section.
In terms of marine operation, the selected digital solution allows engineers to assess the subsea deveolopment by visualising geohazards and clashes during SIMOPS, this aspect adds singnificant value to projects for faster decision making whilst taking into consideration safety.
Production Optimization and Value Maximization of a Giant Ultra-Sour Gas Carbonate Reservoir, Onshore Abu Dhabi
Authors: Ghassan Majed , Fernandes Martin , Al Ali Onood , Kaczorowski Norman 
Published: March 2022

Abstract
This paper describes how the reservoir team at ADNOC Sour Gas developed the ability to dynamically adjust and manage their production strategy based on plant product output and market requirements, driving profitability and maximizing value of the sour gas assets of the UAE.
The reservoir team developed and successfully implemented an extensive data acquisition program, enabling adequate characterization of a giant ultra-sour gas carbonate reservoir in the Late Jurassic Arab Formation in the western area of Abu Dhabi.
The field is located in the southern part of UAE, in the Liwa province, and covers an area of 57 km2. It consists of four main reservoir zones: Arab A, Arab B, Arab C, and Arab D. Current development is focused on the central part of the field with most of the wells dedicated to Arab C. Future development plans will focus on the southern and northern areas of the field.
Early during the appraisal stage, the data suggested the existence of an areal gradient in composition across the reservoir. As such, a clear understanding of this areal distribution in addition to the usual reservoir gas composition, properties and behavior was essential in optimizing field production and maximizing value.
Over the course of field development, reservoir fluids from different well locations were sampled and analyzed. Various issues were encountered during this process including H2S stripping in down hole samples, contamination from stimulation fluids and quality assurance and quality control concerns in lab measurements. Resolving these issues allowed a coherent understanding of the compositional variation in the Arab Formations.
To properly model the compositional variation, an innovative methodology was implemented by the team to initialize the dynamic model. The methodology consisted of two major steps. Firstly, PVT data was analyzed and correlations between H2S and other components were developed. Secondly, through PETREL, compositional maps were created. Ultimately, each grid block was assigned a unique composition honoring the areal variation in composition across each reservoir zone.
In addition, empirical correlations between fluid components and plant product streams were developed through material balance analysis. Using product models, these correlations were input into the dynamic model which allowed estimated plant products to be output directly from simulation runs. Simulation forecasts of estimated plant products were later verified by actual plant yields, giving confidence in the methodology implemented. Further, this method allowed a quick turnaround in production planning and optimization thereby reducing the reliance on a fully- fledged plant simulator for short term gains and quick wins.
Improvement of CSS Method for Extra-Heavy Oil Recovery in Shallow Reservoirs by Simultaneous Injection of in-Situ Upgrading Catalysts and Solvent: Laboratory Study, Simulation and Field Application
Authors: Vakhin Aleksey , Sitnov Sergey , Mukhamatdinov Irek , Varfolomeev Mikhail , Rojas Allan , Sabiryanov Raushan , Al-Muntaser Ameen , Sudakov Vladislav , Nurgaliev Danis , Minkhanov Ilgiz , Amerkhanov Marat , Akhmadullin Robert 
Published: March 2022

Abstract
In this work method to improve the efficiency of the development of shallow deposits of extra-heavy oil using cyclic team stimulation (CSS) technology together with injection of catalyst for in-situ upgrading and solvent was proposed. Oil-soluble catalyst has been developed. Efficiency of catalyst was proved in laboratory. Volume and conditions of catalyst and solvent injection together with steam were determined based on simulation results. Pilot tests of technology were carried out on extra-heavy oilfield in Tatarstan, Russia.
The screening of catalysts and solvents together with injection of steam was studied in high pressure reactors under reservoir conditions. Heavy oil displacement coefficients in basic scenario of steam injection and second scenario of steam injection together with catalyst and solvent were measured on self-designed experimental steam injection apparatus.
The technology was simulated with tNavigator softwarre (Rock Fluid Dynamics) version 18.2, STARS. Pilot tests were carried out in several stages: preliminary short-term injection of steam to pre-heat the reservoir, injection of catalyst solution and solvent, the subsequent full-scale stage of steam injection, imbibition, and production. The results of field tests confirmed laboratory and simulation data. According to the analyzed samples after six months of field tests, the viscosity at the first stage decreases as a result of dilution with a solvent. The effect of the catalyst, which particles are adsorbed on the reservoir rocks, clearly demonstrated later.
It is shown that the combined use of in-situ upgrading catalyst and a solvent in CSS method allows to increase oil recovery factor. At the same time, the produced oil has better properties. Significant degree of conversion of resins and asphaltenes to light fractions was established. Field tests on Ashal'cha oilfield have shown that this technology is effective for the development of shallow deposits of extra-heavy oil.
Numerical Analysis of Surfactant Application in Water-Wet Naturally Fractured Reservoirs
Authors: Hoffmann Eugen , Alakbarov Samir 
Published: March 2022

Abstract
High heterogeneity and complex fluid flow behavior aggravates the recovery by conventional means from naturaly fractured reservoirs (NFRs). The last years have seen an increasing interest and a lot of laboratory and field tests were perfomed with the surfactants as Enhanced Oil Recovery (EOR) agents for this type of unconventional reservoirs. However, most of the attention was focused on application of the surfactants in mixed- to oil-wet conditions and not much is reported for the water-wet rocks. The aim of this study is to better understand and provide the quantitave analysis of the low interfacial tension (IFT) aided surfactant EOR mechanisms in water-wet NFRs. For this purpose, the previously published experiments are reproduced by means of numerical modeling employing commercialy available CMG simulator.
Static and dynamic imbibition experiments in water-wet core samples performed by Schechter et al. (1994) and by Al-Quraishi (2004) respectively, showed incremental oil recovery effects of low IFT surfactants. Using the reported data and boundary conditions, conceptual numerical models are built for each of the experiments. In addition to numerical simulations, manual calculations of the Bond Number, which is not accounted for in the numerical simulator, has given a detailed insight on the balance between capillary and gravitational forces as well their contribution on oil desaturation.
Simulation results of low IFT static imbibition experiments without initial water saturation have shown that the critical capillary numbers used for the matching of the experiments are orders of magnitude lower than those typically reported in literature. Calculation of the Bond number values also revealed that the observed low IFT incremental recovery effects cannot be explained by intensification of the gravitational forces.
On the other hand, numerical analysis of dynamic imbibition experiments indicated considerable contribution of viscous forces towards incremental oil recovery, in contrary to conventional believe that the visous forces have limited effect on recovery from NFRs. The conducted numerical simulation study revealed that contribution of low IFT aided gravity forces on oil desaturation is minor.
Overall the performed study revealed the weak contribution of the gravitational forces on oil desaturation in low permeability cores. Evaluation of the Bond numbers from the experiments, suggested that reduction to ultra-low IFT values can help to achieve the reasonable effect of gravity forces on recovery. However, the validation of this postulate requires implementation of further studies and laboratory experiments.