bluuebunny/crossref_metadata_2025_split huggingface dataset:
Molecular Magnet Induced Transformative Effects in Molecular Spintronics Devices: A Monte Carlo Study
Authors: D’Angelo Christopher , Tyagi Pawan 
Published: April 2013

ABSTRACTMolecular spintronics devices (MSDs) are capable of harnessing the controllable transport and magnetic properties of molecular device elements and are highly promising candidates for revolutionizing computer logic and memory. A MSD is typically produced by placing magnetic molecule(s) between the two ferromagnetic electrodes. Recent experimental studies show that the molecules produced unprecedented strong exchange couplings between the two ferromagnets, leading to intriguing magnetic and transport properties in a MSD. Future development of MSDs will critically depend on obtaining an in-depth understanding of the molecule induced exchange coupling and its impact on MSD’s switchability and temperature stability. However, the large size of MSD systems and unsuitable device designs are the two biggest hurdles in theoretical and experimental studies of magnetic attributes produced by molecules in a MSD. This research theoretically studies the MSD by performing Monte Carlo Simulation (MCS) studies, which have the capacity to tackle large systems- such as MSD based on magnetic tunnel junction (MTJ) test bed. The MTJ based MSD has the distinctive advantage that MTJ test bed can be subjected to experimental magnetic characterizations before and after transforming it into a MSD by bridging the molecules of interest between the two metal electrodes of a MTJ. Hence the result of our MCS can be verified experimentally.
Prevalence, Cause, and Location of Palatal Fistula in Operated Complete Unilateral Cleft Lip and Palate: Retrospective Study
Authors: De Agostino Biella Passos Vivian , De Carvalho Carrara Cleide Felício , Da Silva Dalben Gisele , Costa Beatriz , Gomide Marcia Ribeiro 
Published: April 2013

Objective To evaluate the prevalence of fistulas after palate repair and analyze their location and association with possible causal factors. Design Retrospective analysis of patient records and evaluation of preoperative initial photographs. Setting Tertiary craniofacial center. Participants Five hundred eighty-nine individuals with complete unilateral cleft lip and palate that underwent palate repair at the age of 12 to 36 months by the von Langenbeck technique, in a single stage, by the plastic surgery team of the hospital, from January 2003 to July 2007. Interventions The cleft width was visually classified by a single examiner as narrow, regular, or wide. The following regions of the palate were considered for the location: anterior, medium, transition (between hard and soft palate), and soft palate. Main outcome measures Descriptive statistics and analysis of association between the occurrence of fistula and the different parameters were evaluated. Results Palatal fistulas were observed in 27% of the sample, with a greater proportion at the anterior region (37.11%). The chi-square statistical test revealed statistically significant association ( P ≤ .05) between the fistulas and initial cleft width ( P = .0003), intraoperative problems ( P = .0037), and postoperative problems ( P = .00002). Conclusions The prevalence of palatal fistula was similar to mean values reported in the literature. Analysis of causal factors showed a positive association between palatal fistulas with wide and regular initial cleft width and intraoperative and postoperative problems. The anterior region presented the greatest occurrence of fistulas.
Successful Field Implementation of a Novel Solids-Free System to Control Fluid Loss During Overbalanced Workover Operations in Southern Argentina
Authors: Vasquez Julio , Bonapace Juan , Gonzales Javier , Quintavalla Rodrigo 
Published: April 2013

Abstract
During workover and completion operations, even a small overbalanced hydrostatic pressure can result in a significant loss of fluid to the formation, especially in high-permeability formations. This situation becomes even more drastic in depleted reservoirs, horizontal wells, or in zones that have been previously fractured and packed. Controlling fluid loss into the formation is of critical importance during overbalanced workover operations to minimize near-wellbore (NWB) damage invasion by the completion fluid, which can yield problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. In many hydrocarbon fields in southern Argentina, controlling fluid loss before NWB cleanout treatments is challenging because it can cause pressure differential sticking of the coiled tubing (CT) and/or inability to pump the treatment into the desired interval. This paper presents the successful field application of a novel solids-free fluid-loss (SFFL) system during wellbore cleanouts in the Cerro Dragon oilfield, which is located on the west side of San Jorge Gulf (SJG) basin in the Chubut Province of Argentina.
The SFFL system relies on water-soluble polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock, eliminating the need to shut the well in. In addition, this system does not require the use of breakers or a cleanup stage to reestablish hydrocarbon production once the workover operation has been performed. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment.
To date, about 200 treatments have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations in Argentina, including the job design and post-treatment results. This system has been proposed for returning partial and total loss to full circulation in overbalanced operations, such as (1) lost-circulation events occurring during cementing, fracturing and drilling, (2) well intervention cleanouts by CT and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (UTCP).
A Practical Economic Optimization Approach with Reservoir Flow Simulation for Infill Drilling in a Mature Oil Field
Authors: Al-Mudhafer Wathiq J. 
Published: April 2013

Abstract
A practical optimization approach has been coupled with a commercial reservoir simulator to evaluate the optimal number and locations of infill wells in a conceptual sector of the Main Pay in South Rumaila Oil Field in Iraq. This field, of 58-years of production, has 40 producing wells. There is also an edge water drive from the infinite active aquifer at the east and west flanks. The water drive from the west flank is more than 20 times the drive from the east flank. Therefore, twenty injection wells have been drilled located at the east flank to maintain and balance the reservoir pressure.
After achieving the reliable history matching and running the simulator for a future period until 31 December 2020, the optimization approach has been implemented via spreadsheet considering the aspects of Net Present Value as objective function. The Net Present Value (NPV) is a function of economic variables representing costs and revenues. The revenue is directly proportional to the cumulative oil production that has been predicted by the reservoir model for the entire field. The costs include capital (CAPEX) and operational (OPEX) expenditures. There are ten assigned location of wells taken as a premise to be production wells. These 10 locations have been ranked according to the highest value of permeability and oil saturation spatial distribution in the reservoir in order to be evaluated considering achieving the highest NPV. The optimal number of infill wells was three, six, and ten when the NPV is calculated by the end of 2015, 2017, and 2022, respectively and all the wells at the three cases located at the crest of the reservoir. These optimal wells don't have the maximum cumulative oil production; however, they have the maximum Net Present Value especially at the first two prediction cases.
A Comparison between Capillary and Electrical Properties of Rock Samples Obtained at Ambient Conditions and Reservoir Conditions
Authors: Aboujafar Sami M. , Amara Mohamed A. 
Published: April 2013

AbstractDetermining the capillary pressure behavior of rocks at reservoir temperature and pressure is vital in understanding the displacement mechanism in the reservoir. An understanding of the displacement mechanism is essential to evaluate its effect on fluid saturations and oil recovery. The evaluation of saturations and thus oil reserves from resistivity logs requires laboratory determination of both the cementation factor (m) and the saturation exponent (n) under conditions as representative as possible of reservoir ones. Special laboratory equipment using air and actual formation brine at reservoir temperature and under effective overburden pressure was developed. The porous plate method was used to determine capillary pressure curves and saturation exponent at ambient conditions and at full reservoir conditions, (reservoir pressure and temperature) on sandstone core plugs from a Libyan reservoir.The main objective of this study was to determine whether any difference exists between the capillary and electrical properties obtained at ambient conditions and those obtained at reservoir conditions for rock samples. Prior to the test, the effect of overburden pressure on porosity and formation factor can be studied.
SPDC Delivers 1st Onshore Smartwell Through Constructive Engagement with Stakeholders (Partners/Regulators/Internal SPDC)
Authors: Okpokpor O. A. , Nnanna E. , Otutu F. , Alabi I. B. , Azoom l , Uchendu C. C. , Oguntimehin A. B 
Published: April 2013

Abstract
Smartwell has become a routine technology solution in various parts of the world (including Nigeria) but is yet to receive total acceptance in Nigeria as the Industry regulators have remained opposed to commingled production pending demonstrable evidence of production allocation to individual producing reserves. It is still a frontier project in Nigeria and therefore requires a dedicated and concerted approach of winning stakeholders' acceptance. Various challenges, ranging from risk aversion to fears of a repeat first attempt ‘partial success' experience, contributed to the current low (near zero) performance of Shell Nigeria in the Nigerian Smart Completion deployment hierarchy. Notably, Chevron is the industry leader in Nigeria with over 22 wells while Shell Nigeria is about the last with only one attempt. The single ‘failed' attempt of the technology in 2002 gave rise, in 2004, to a deployment strategy change which met with an opposition both internally and externally. Undeterred by the challenge of persuading all stakeholders to embrace a repeat trial, work continued assiduously towards ensuring that the technology benefits are fully harnessed/realized through an aggressive and transparent approach of constructive stakeholders' engagements, development of pragmatic contracts and detailed researches into best practices. This paper presents a transparent and focused approach adopted through all stages of the project, which culminated in the final ‘textbook' Smartwell deployment. It also outlines how stakeholders involvement in the Major Smartwell contract initiation and award coupled with a collective orchestration of deployment planning further enabled a hitch-free deployment. Notably, this paper buttresses how the quest for success assurance and building of stakeholders' confidence, culminated into the constitution of a project deployment team comprising of operator, Partners, regulators and Contractors' representatives. The project team was tasked with the responsibility of working collaboratively to ensure success of the deployment as it would enable the next FDP for the field.
Reservoir Management Tool-Kits in Offshore Khafji Field: Successful Solutions for Field Case Studies on Water Conning Problems in Sandstone Reservoirs
Authors: Moawad Taha M. , Al-Dhafeeri Abdullah M. , Mohamed Tawakol I. 
Published: April 2013

Abstract
A sandstone reservoir (SA) is the main producer reservoir in offshore Khafji oil field. This field has been producing since 1959. However, for time being, some wells suffer from excessive water production especially in old vertical wells. In addition, early water breakthrough in vertical wells is mainly due to high permeability streaks and unfavorable mobility ratio.
Therefore, controlling water production is a challenge for reservoir management team work in Khafji Joint Operations (KJO) because there are several different explanations for the water sources in SA sandstone reservoir. These sources could be one or combination of edge water movement and flow behind casing. This phenomena can occur due to high permeability streaks, and conductive channels or/and faults.
To sustain the KJO Maximum Sustainable Capacity (MSC), reservoir management in KJO should apply optimum development scenarios for reducing the water production utilizing several and effective water shut-off techniques due to production facility bottlenecks. Converting the old and high water production vertical wells to horizontal and lateral wells which have shown a high rate of success in terms of conducting better technique and scenario to retrieve and bring these wells into production with low water cut. The approaches included also reducing the choke size, cement jobs to shut-in watered out intervals and adding new perforations or re-perforating oil productive intervals. Several successful field cases have been applied in SA reservoir which resulted to high oil production with low water cut. This paper discussed more details of lessons learned and applied techniques to control excessive water production from oil wells and comparison in selecting them for applying optimum applicable techniques.
The results of water management techniques and scenarios to retrieve the wells are analyzed and discussed in this study. Reasons for conversion, directions, diagnosis, selected intervals, simulation results analysis, lessons learned, challenges and conclusions were addressed in this paper.
Flow assurance for subsea gas production systems in the deep water of Mediterranean Sea with lower glycol injection rates.
Authors: A.Moati Wael Hamed 
Published: April 2013

Abstract
Flow assurance is an engineering process provides comprehensive analysis to assure hydrocarbon fluids are transported through pipelines (small lines or trunk lines) in an economical and safe manner from the producing wells to the treatment plant. Thus, flow assurance covers the whole range of possible flow problems that can trigger in pipelines such as hydrate formation, erosion, and severe slugging or back pressure to the old producing wells if they are connected to the same network. This paper introduces a case study done on a new gas field named "Denise-B?? located in the Mediterranean Sea, Egypt.This field is planned to be on production after finishing drilling and completion phases of three wells (Denise-4, Denise-5 and Denise-S4). The main scope is to optimize the whole network to select the best development rates of the new field without any back out from the old producing ones. At the same time, overcoming any flow problems like hydrate formation since offshore wells and offshore transmission lines may be operating under conditions where hydrate formation is favorable. The paper highlights that the change of inhibitor from di-ethylene to mono-ethylene glycol has a significant impact on the required injection rates. It is found that using mono-ethylene glycol compared to di-ethylene glycol can save up to 45% of the required volume rate to lower the hydrate temperature with 5 0C margin with flowing gas temperature. This is also is linked to properly design the injection pump capacity. Hence; it enhances the confidence and supports the decision to use mono glycol as hydrate inhibitor at low injection rates in offshore gathering networks while reducing the operating costs.
Introduction
Some of the most severe production-operation hazards are risks associated with the transportation of fluids. When condensate, water, and gas simultaneously flow in a well or pipeline, a number of potential problems can arise. These problems can be related to flow instability, erosion, and solids formation (like hydrates) and can lead to serious risk of leakages or blockages. The pipeline simulation tools can be used to simulate the steady state of the gathering network that collects the production of fluids from different gas or oil fields. Thus; it can provide a quick but efficient view of the system highlighting its criticalities that require more attention from operational point of view.
Using Simple Analytical Approach in Estimating Remaining Resources and Evaluating a Long Shut-In Reservoir Compartment with Too Many Uncertainties
Authors: Darhim Noureldien M. , Nassar Ibrahim S. 
Published: April 2013

Abstract
M8 Complex is one of the hugest and oldest offshore platforms in Gulf of Suez, Egypt. Many Intensive studies are conducted to refurbish it after its accidental fire occurred in March 2004 destroying most of its structure parts in a try to reinstate its production (±5000 BOPD). M8 receives oil feed from 5 satellites which are producing from Kareem reservoir (Middle Miocene) through a total of 11 wells penetrating M8 compartment polygon.
The main challenge is that 3 of the 11 wells are drilled from another outside platforms which are not related to M8 as a complex but their effect still inside M8 Polygon; these 3 wells continued production even after M8 fire. Also some WIW's accidently still injecting inside the polygon during its shut-In period till now. That led to a more complications in calculating remaining volumes of hydrocarbon left in the reservoir because all parameters inside M8 compartment polygon have been dramatically changed since 2004 till now.
This paper presents a study to decide whether to refurbish and reclaim M8 or not which depends mainly on the current remaining hydrocarbon volume. It shows also a simple analytical approach used for accurately calculating the remaining resources leading to take appropriate decision. Paper also covers many recovery scenarios, challenges and uncertainties specially in locating oil pockets and estimating initial rate after reinstating.
Through this paper you will learn how to use a simple analytical approach to solve such a complicated problem. Paper will explain the Study Methodology, Volumetric Calculations, STOOIP Validation, RF Estimation & QC, WIW's effect during the Shut-In period, de-risking all uncertain parameters and Finally finding optimum method to recover the remaining volume & How to choose the optimum location(s) of the proposed producer(s) to be drilled – all of this by only using a conventional approach.
An Approach To Determine Sandstone/clastic Reservoir Rock Distribution Pattern In Fluvio-deltaic- Marginal Marine Environment - An Easy, Simple And Cost Effective Process.
Authors: Deb Sasanka Sekhar , Borgohain J. K. , Basha S. K. 
Published: April 2013

Abstract
Depositional environment of a sedimentary sequence plays a vital role in the nature of sediments and distribution pattern of sediments. Environment of deposition is generally determined by sedimentological study, wire line log interpretation from well data of specific locations. The spatial extrapolation in to nearby areas can not be done alone by sedimentological study/ log interpretation. There are a number of techniques / tools available to identify the distribution pattern of sediments deposited in different environments of a stratigraphic sequence. Sequence stratigraphy is now a well established technique for determining sediment distribution pattern in a sedimentary sequence deposited in varied depositional environments. This special technique requires an in-depth knowledge of the subject and sufficient palaeo-geological information about the study area. Often, it becomes difficult to conceptualize the basic framework of the sequence stratigraphy method due to limited regional information and scanty data. As for example in fluvio-deltic-shallow marine conditions with active sea level fluctuation coupled with rapid fluvial sedimentation, sporadic palaeogeographic information hampers conceptualization of geological model. In such a situation another technique can help in solving some of the uncertainties in depositional setting. Basic concepts of Sequence stratigraphy coupled with sand (reservoir) shale (nonreservoir) ratio mapping provide excellent result in identifying depositional pattern of reservoirs units. This is a simple, easy and cost effective way to understand the broad depositional setting of sediments without involving high technology/gadgets.
A case study from an area within the petroliferous Upper Assam Basin of Assam-Arakan geological province of India is presented here.
Rejuvenation of West Qarun Field
Authors: El-Behairy A.. , Abdel-Nabi M.. , Rizk Mahmoud , Abdel-Moneim E.. 
Published: April 2013

AbstractThe West Qarun development concession is located in the Abu Gharadig basin of the Western Desert, approximately 200 km SW of Cairo City. The block comprises a gross area of 46.2 km2 and contains the producing West Qarun oil field. Oil production commenced in October 1994 from four wells with initial production rate 1200 BOPD. The field showed constant production for the last ten years before SOG acquired the concession at a level of ±500 BOPD. The cumulative oil production amounted to 6 MMSTB of 40 deg API non-sulfurous, slightly low gas-oil-ratio paraffinic crude mainly from the Abu Roash ‘G’ and Upper Bahariya reservoirs through fifteen wells.SOG after acquiring the concession, in 2009, conducted 3D seismic survey in order to reveal the uncertainties concerning field structure and its interpretation opened new chances by indicating higher OOIP and new promising locations for drilling. The results of new drilled wells WQ-7, WQ-9, and WQ-10 proved the new interpretation and gave more confidence in the resulted figures.The Abu Roash "G" producing sands are characterized by formation tightness. So applying of hydraulic fracturing technique to enhance the existing wells productivity showed excellent results. Also tight formations need large shut-in time to obtain accurate pressure measurements. Therefore a pilot test was conducted to study the effect of shut-in time on the pressure measurements which will be illustrated thereafter.Based on the studies, a complete development plan was prepared and the application of the first stage resulted in increasing the production five times (from 500 to 2500 BOPD) and tripling the proven remaining reserves as well (from 6.3 MMSTB to 19.5 MMSTB).This paper will illustrate the approaches applied for the rejuvenation of West Qarun field and emphasizes the role of reservoir characterization and reservoir management in maximizing the field value.