bluuebunny/crossref_metadata_2025_split huggingface dataset:
Macrophage migration inhibitory factor (MIF) promotes cell survival and proliferation of neural stem/progenitor cells
Authors: Ohta Shigeki , Misawa Aya , Fukaya Raita , Inoue Satoshi , Kanemura Yonehiro , Okano Hideyuki , Kawakami Yutaka , Toda Masahiro 
Published: March 2012

In a previous study, we showed that murine dendritic cells (DCs) can increase the number of neural stem/progenitor cells (NSPCs) in vitro and in vivo. In the present study, we identified macrophage migration inhibitory factor (MIF) as a novel factor that can support the proliferation and/or survival of NSPCs in vitro. MIF is secreted by DCs and NSPCs, and its function in the normal brain remains largely unknown. It was previously shown that in macrophages, MIF binds to a CD74-CD44 complex. Here, we observed the expression of MIF receptors in mouse ganglionic eminence (GE)-derived neurospheres using flow cytometry in vitro. We also found CD74 expression in the GE of E14 mouse brains, suggesting that MIF play a physiological role in vivo. MIF increased the number of primary and secondary neurospheres. In contrast, retrovirally-expressed MIF shRNA and MIF inhibitor (ISO-1) suppressed primary and secondary neurosphere formation, as well as cell proliferation. In the neurospheres, MIF knock-down by shRNA increased caspase 3/7 activity, and MIF increased the phosphorylation of Akt, Erk, AMPK, and Stat3 (Ser727), as well as gene expression of Hes3 and Egfr, which are known to support cell survival, proliferation and/or maintenance of NSPCs. MIF also acted as a chemoattractant for NSPCs. Taken together, MIF can induce NSPC proliferation and maintenance by using multiple-signaling pathways synergistically, and it may be a potential therapeutic factor capable for NSPC activation for the treatment of degenerative brain disorders.
Trimethylsumanene: Enantioselective Synthesis, Substituent Effect on Bowl Structure, Inversion Energy, and Electron Conductivity
Authors: Higashibayashi Shuhei , Tsuruoka Ryoji , Soujanya Yarasi , Purushotham Uppula , Sastry G Narahari , Seki Shu , Ishikawa Takeharu , Toyota Shinji , Sakurai Hidehiro 
Published: March 2012

Abstract
C 3 symmetric chiral trimethylsumanene was enantioselectively synthesized through Pd-catalyzed syn-selective cyclotrimerization of an enantiomerically pure iodonorbornenone, ring-opening/closing olefin metathesis, and oxidative aromatization where the sp3 stereogenic center was transmitted to the bowl chirality. Chiral HPLC analysis/resolution of the derivatives were also achieved. Based on theoretical calculations, the columnar crystal packing structure of sumanene and trimethylsumanene was interpreted as due to attractive electrostatic or CH–π interaction. According to the experimental and theoretical studies, the bowl depth and inversion energy were found to increase on methylation for sumanene in contrast to corannulene. Dissimilarities of the effect of methylation on the bowl structure and inversion energy of sumanene and corannulene were ascribed to differences in steric repulsion. A double-well potential model was fitted to the bowl structure–inversion energy correlation of substituted sumanenes, with a small deviation. The effects of various substituents on the sumanene structure and bowl-inversion energy were analyzed by density functional theory calculations, and it was shown that the bowl rigidity is controlled by a combination of electronic and steric effects of the substituents. The electron conductivity of trimethylsumanene was investigated by time-resolved microwave conductivity method, compared with that of sumanene.
Identification of Secondary & Tertiary Precipitants of Sandstone Acidization Allows Minimization of Formation Damage: A Laboratory Study
Authors: Kumar Ajay , Yadav N. , Rao YRL , Singhal C. P. , Kumar Ajit 
Published: March 2012

Abstract
The Nandasan field discovered in 1969 is a multi-layered reservoir in western part of India and producing oil & gas with little problem as it is having good porosity and permeability. Deeper multi layered mehsana formation comprises of 45% silicon, 9%aluminium, 18%iron, 0.23%calcium, 0.47%potesium, 12%other heavy metal having montmorillonite, Kaolinite and Chamosite clay. Several mud acid treatments have been performed successfully in the shallow depth but the same is not quite effective for deeper pay zone (1700-1800m). Core flow study with mud acid through indicates some precipitation resulting in formation damage and its success in field is limited. Therefore, greater understanding of down hole chemistry and assess the extent of the much slower secondary and tertiary reactions under reservoir conditions is critical for the acid treatment success. Monitoring of metallic ion generation during / after various acidizing treatments gives insight into actual chemical acid-spending processes that occur in the formation.
In the laboratory study, four type of different acid system has been tried with representative core and the resultant dissolution and metallic ion generation processes has been monitored for 3 hours using atomic absorption spectrometry followed by core flow study. Aluminium, Silicon and Iron complexes precipitation observed during secondary and tertiary reaction has been successfully tailored by changing the ratio of HCl:HF and other additives in traditional mud acid system. Results show that RA-1(AlCl3+ HF) acid is little reacting with Silicon whereas RA-2(Phosphonic acid+ ABF) creates Silicon & Calcium precipitation since beginning, thus not suitable. Similarly, RF(HCl+HBF4) creates Silicon precipitation after 150 min in tertiary reaction, whereas, MHF(HCl-HF) acid creates Al precipitation in secondary reaction and Iron precipitation since beginning that is resolved by increasing HCl:HF ratio and adding iron sequestering agent. Core flow study confirms the success of MHF by observing permeability improvement, therefore, suitable for matrix acidization of mehsana formation.
This paper presents a new, effective and economical technique to assess and understand the extent of secondary & tertiary reactions under reservoir conditions that will help in additives selection and making acid formulation for effective matrix acidization of sand stone reservoir that leads to improved field practice.
A New Petrophysical Interpretation Approach To Characterize The Thinly Laminated Reservoir Using Conventional Tools
Authors: Voleti Deepak , Tyagi Anil , Singh Amit , Mundayat Vidya , Pandey Vikram , Saxena Kamlesh 
Published: March 2012

Abstract
Reservoir characterisation in laminated sand shale reservoir has always been a very challenging task. The presence of conductive shales between the resistive hydrocarbon bearing sand reduces its resistivity drastically. It happens as the current flows through them as resistors in parallel. Therefore, the classical shaly sand interpretation grossly underestimates the hydrocarbon potential of laminated reservoir.
Over the years many techniques have been developed to solve this problem. The development of latest resistivity tools like triaxial resistivity has also helped in addressing this problem. The introduction of these tools has helped upto a great extent to unlock the reservoir potential. However, the technology is very costly and sometimes may not be possible to run due the limited extent of the reservoirs. In those cases, it is important to find some alternate approach to addres the problem of low resistivity by using conventional logging tools.
The current study deals with the case history from the East coast deep water field in India. The field has many drilled wells where the latest resistivity tools have been run. Petrophysical interpretations are done using this resistivity anisotropy data and are available for validation with the new technique. The latest approach uses the conventional resistivity data. The critical part in the study is the type and distribution of the shale within the reservoir. If we can find out the same then using this information true resistivity can be inverted. The approach has been tried on several wells across the different fields and has given good results. The results from the resistivity anisotropy data and the new technique are comparable. Thus a very cost effective method of predicting true resistivity has been developed, which ultimately gives realistic hydrocarbon saturation in the laminated sand shale sequences.
Combining State-of-the-Art Uncertainty Management Approaches with Conventional Reservoir Assessment Techniques for an Integrated Brownfield Redevelopment Study
Authors: Hofmann Richard A. , Rana Yogesh , Ratha Bishnu P. 
Published: March 2012

Abstract
This paper describes the results of an integrated study to assess redevelopment options in a mature field with over 40 years of production. The field has been produced under gas cap drive and partly under an internal gas injection scheme to increase oil recoveries. The objective of the study was to confirm the effectiveness and possible expansion of the gas injection scheme and to assess merits of waterflooding.
A two phased modeling approach was adopted and a coarse Phase 1 model for the entire reservoir stack was built using existing interpretations and data available from previous studies while seismic reinterpretation and petrophysical reevaluation to feed the detailed Phase 2 models was ongoing. The Phase 1 model helped to understand the plumbing between the sands and fault blocks and the key parameters impacting field level pressure and cumulative fluid history matches. In Phase 2, two separate models were built for groups of reservoirs at a much finer vertical scale to address sand specific saturation changes and individual well performance.
A structured experimental design (ED) methodology using SUM (Shell proprietary software) was used to explore the full uncertainty space for potential history matches and use calibrated models with the remaining uncertainties to generate a range of forecasts. With the large number of reservoirs involved even a modest number of uncertainties resulted in a large number of ED parameters. The number of parameters and their associated uncertainties was partly narrowed down and constrained in Phase 1 allowing focusing on detailed reservoir specific parameters in Phase 2. In parallel with and complementing the simulation work, conventional contact mapping integrating the historical pressure, water cut and GOR data was carried out to locate potential areas with remaining oil.
This paper will highlight how the phased modeling approach facilitated early integration of reservoir and well performance data for detailed static model construction, ways of managing uncertainty in a brown field with multiple reservoirs, large number of wells and more than 40 years of production history, and finally how traditional reservoir assessment techniques can complement reservoir modeling work.
Injection Water Breakthrough Patterns in Bassein Formation Of Heera Field-A Case Study, Western Offshore, India
Authors: Jha Mamta , Sharma S. S. , Virmani R. K. , Kumar Ajit 
Published: March 2012

Abstract
Heera field is located 70kms south-west of Mumbai city and 140 kms south-east of Mumbai High at an average water depth of about 50m. The field was put on production in November ’84. The oil production is mainly from Bassein, Mukta (carbonates) and Panna (basal clastics) formations. The general dip of the field is towards west. The field produced under depletion drive for about six years till Sept. 90. By this time the reservoir pressure dropped to 1300psi from 2150psi and the field experienced sharp decline in production. Water flooding in Bassein formation started in September ’90. The production stabilized for some time and then again started declining with a sharp rise in water cut. Current average oil rate from the field is 55,892 bopd with water cut of 56% and GOR 145 v/v through 152 producing strings. The average water injection is 1,36,800 bwpd.
The present study aims to identify injection water breakthrough patterns in the producers of Bassein formation of Heera field. The study area is the upper part of mid-Heera field comprising of wells of platforms HD, HQ, HR and HA. The sudden rise in high water content could be due to the breakthrough of injection water in to the producers. Spider diagrams and contour maps were used to interpret the injection water breakthrough patterns in the study area.
Areal distribution pattern as indicated by contour maps of different ions in the study area suggest that there is more influx of injection water in the wells lying on the rising flank of the basin. In the down dip effect of injection water is less. Wells of HA and HD lying on the eastern side are more affected by influx of injection water than wells of platform HR and HQ.
Production Simulator Utilisation for Deep Water Field Optimisation
Authors: Shedd Timmie D , Krishna Sivarama V , Misra Deepti , Mahra Anuradha 
Published: March 2012

Abstract
This paper describes the wide application of Production Simulator System in deep water gas field, its benefits and effectiveness. Deep water and subsea production system requires transportation of a mixture of gas/water through long subsea tiebacks from the producing well to existing production facilities.
Production Simulator System is extensively utilised by Subsea operators for planning their day to day operations and predicting the systems response to current conditions and/or operator actions. The networked production software allows users to optimise and improve the system performance by monitoring wells and facilities.
The optimisation process goes beyond basic operations, but extends into predicting impact of wells/manifolds start-up/shut down, subsea interventions on system performance and its deliverability. The tool also provides study on the integrity of subsea pipelines and critical flow for mid water pipelines to prevent shutdown of manifolds. Simulation studies have presented results, which were precisely similar to the real time data.
While use of long subsea tie backs allows for better project economics, long flowlines causes additional backpressure on the well tending to reduce flow rates due to liquid hold up and/or backpressure increase thereby affecting ultimate recoveries. The succeeding sections in this paper will discuss how such tie-backs tend to under-utilise reservoir energy and presents alternatives for improving field life and enhance the system efficiency.
Efficient monitoring of subsea gas well behavior, subsea system integrity, analyzing subsea pipelines performance and predicting problems with the software optimisation tool has resulted in significantly decreased downtime and effectively assisted in taking decisions for maintaining well production.
ASP Flood Pilot in Jhalora (K-IV) - A Case Study
Authors: Jain Adarsh Kumar , Dhawan A. K. , Misra T. R. 
Published: March 2012

Abstract
Jhalora field, discovered in 1967, is located in the Ahmedabad-Mehsana tectonic block of Cambay basin in India. Reservoir and crude oil properties of all the three main producing sands K-III, K-IV and K-IX+X are quite different. Viscosity of K-IV sand is ~30-50 cp and permeability varies between 1.9 to 8.7 Darcy. Acid number of crude oil is quite high. Water cut is between 80-85%. The mature stage of the Jhalora K-IV with heterogeneous reservoir characteristics and unfavourable mobility ratio makes it an ideal choice for application of chemical EOR technique to enhance the recovery. Based on extensive laboratory and simulation studies one inverted 5-spot pilot was designed. The laboratory studies envisaged additional displacement efficiency of about 23% of Oil Initially in Place (OIIP). Pilot envisaged injection of 0.3 pore volume (PV) Alkali-Surfactant-Polymer (ASP) slug, 0.3PV graded polymer buffer followed by 0.4PV chase water. In order to check preferential movement in the pilot area, profile modification job was done before initiation of pilot. To monitor flood front movement, chemical tracer was also injected.
A meticulous monitoring schedule was drawn. Monitoring is done by measurements of pH, turbidity, Dissolved Oxygen, concentrations of alkali, surfactant & polymer of ASP slug being injected on regular basis. Monitoring schedule also involves fortnightly checking of production rates for each well & weekly testing of water cut. Well head samples from pilot wells are collected on weekly basis and analysis of produced water for presence of tracer & chemical breakthrough is carried out.
In this paper brief results of laboratory investigation leading to implementation of ASP pilot are given. Detailed results of monitoring, problems encountered along-with various steps taken to ensure smooth injection and performance analysis of this pilot so far are given.
Initial results of the ASP pilot are encouraging with additional oil gain of about 47000 bbls after injection of about 0.17 PV ASP slug and expansion of the pilot project is being planned.
Making Good HPHT Invert Emulsion Fluids Great!
Authors: Wagle Vikrant , Maghrabi Shadaab , Teke Kushabhau , Gantepla Anita 
Published: March 2012

Abstract
Barite sag and poor hole cleaning are not problems; they are symptoms of well control and stuck pipe problems. Issues with barite sag and hole cleaning are routinely encountered while drilling high pressure high temperature (HPHT) wells. Maintaining optimal mud rheology in HTHP conditions (350°F+) can be very difficult. Adding organo-clays or low gravity solids (LGS) to boost rheology can lead to high equivalent circulating densities (ECD) and low rates of penetration (ROP).
The new HPHT organic rheology modifier (ORM) imparts optimal rheological properties to low, medium and high density clay-free invert emulsion fluids (IEF). Clay-free systems have previously demonstrated superior gel strength and rheological profiles over conventional organo-clay and lignite treated fluids. Although significant improvement in these systems seemed unlikely, this was accomplished with the new ORM chemistry.
These IEFs exhibit enhanced low shear rheology (even at 9.0 ppg) with lower or similar plastic viscosity (PV) values when compared to IEFs formulated without the new HPHT rheology modifier. When tested at up to 400°F and 18,000 psi, the IEFs formulated with ORM show similar or higher low shear rheology with low PV than under ambient condition. A good low shear rheology implies better hole cleaning and sag control. A low PV improves ECD control.
Treatment with ORM imparts fragile gel characteristics to 9.0 to 18.0 ppg clay-free IEFs. The rapid gel-to-flow transition helps to minimize surge and swab pressures and reduce mud losses. The new HPHT rheology modifier with a biodegradability of 67% in 28 days also stabilizes the IEF and provides comparatively low fluid loss values. It also eliminates the need to add LGS to boost rheology. The paper presents experimental data demonstrating both the environmental and rheological performance of the HTHP rheology modifier as well as comparative data from the conventional clay-free fluids without the ORM.
Meeting the Ultra HTHP Fluid Challenge
Authors: Stamatakis Emanuel , Young Steve , De Stefano Guido 
Published: March 2012

Abstract
Ultra high temperature, high pressure (uHTHP) conditions have a different definition depending on the region and the operator and Service Company. In this paper the definition used for uHTHP fluid performance is that of a fluid able to perform above 500°F and 30,000 psi. This paper describes the development of innovative drilling fluids specific to these well conditions. When bottomhole temperatures exceed 400°F, the design and engineering of drilling fluids can be challenging. Drilling fluids that destabilize can cause a variety of fluid control problems that could lead to drilling and completion issues. With Invert emulsion fluids, the major challenges encountered under these conditions are related to the thermal degradation of the emulsifier and wetting package that can lead to gelation and syneresis. Another challenge is fluid loss which is related to the emulsion stability and to the degradation of the fluid loss control additives. Finally, efficient control over the rheological properties – critical to the success of any well - can also be challenging, where effects from emulsion instability, filtration control degradation and rheology control additive degradation are coupled with increases in drilled solids, rapidly leading to rheological instability. This can manifest itself as high fluctuating rheologies and gelation, or loss of rheological properties that can give rise to sag of weight material, both potentially leading to associated well control problems.
The paper describes the development of the new fluid system designed for such uHTHP environments, highlighting the chemical differences and compares the test data of the system with more conventional HTHP invert emulsion fluids. Data is presented showing the stability and performance of the new fluid over extended exposure to temperature &gt;500°F, demonstrating tolerance to various contaminations and showing the rheological behavior and stability to 600°F and 40,000 psi.
An Integrated Cost Effective Approach for Development of Marginal Fields through Cluster system: A Case Study from Western Offshore Basin, India
Authors: Maji Ashish , Mudiar Binod , Raisinghani Chandar 
Published: March 2012

Summary
Development of marginal fields in recent time is gaining popularity in view of higher crude oil prices and declining production from brown fields. The discoveries of large fields in mature basins world over are increasingly rare with time. Crude oil production in India is mainly contributed by Western Offshore Basin fields and is undergoing steady decline. To support and sustain the production, marginal fields which have been discovered and remained undeveloped for economical reasons are being taken up for development through innovative strategies and cost optimization. With improved infrastructure and technologies like Sub-sea completion, minimum facility well platform, availability of FPSO, MOPU, Multi Phase Pumps, host of other new ideas available and utilization of various lift technologies will make these marginal discoveries economically viable.
The Cluster-A consisting of three marginal fields (M-1, M-2 and M-3) located East of Mumbai High field and integrated with M-4 additional development (1 new & 1 Side Track well in M-4 field, 1 new well in M-5 Structure) is the case study of cost effective approach for development and early monetization. The bathymetry of the fields ranges from 40-55m. Hydrocarbon accumulations are established in thin multilayered reservoirs consisting of carbonates and finer clastics having in-place oil and gas of around 109 MM BBL and 0.363 TCF respectively.
These fields were discovered in early nineties. Development of these fields remained uneconomical on standalone basis; however, they become viable through cluster system using existing infrastructure and integrating with redevelopment of a nearby brown field and a recent gas discovery.
The development scheme envisages depletion drive, 11 Producers, MOPU for processing; oil evacuation through shuttle tanker and gas to SHG process complex after compression at wellhead platform and a new pipeline from M-4 to BPB Process complex.
This paper presents the technical and business approaches which are critical for development of these smaller isolated fields / prospects through cluster system.