bluuebunny/crossref_metadata_2025_split huggingface dataset:
Complementary Feeding Knowledge, Practices, and Dietary Diversity among Mothers of Under-Five Children in an Urban Community in Lagos State, Nigeria
Authors: Olatona, MBBS, MPH, FMCPH Foluke Adenike , Adenihun, MBBS Jesupelumi Oreoluwa , Aderibigbe, MBBS, MPH, FWACP Sunday Adedeji , Adeniyi, MBBS, FMCPaed Oluwafunmilayo Funke 
Published: March 2017

Background and Objectives: Inappropriate complementary feeding is a major cause of child malnutrition and death. This study determined the complementary feeding knowledge, practices, minimum dietary diversity, and acceptable diet among mothers of under-five children in an urban Local Government Area of Lagos State, Southwest Nigeria.Methods: This descriptive cross-sectional study was conducted in Eti-Osa area of Lagos State, Nigeria. Multi-stage sampling technique was employed to select 355 mothers and infants. Data was collected using a pre-tested interviewer administered questionnaire and 24-hour diet recall was used to assess dietary diversity. Data was analyzed using Epi-Info.Results: Knowledge of complementary feeding was low (14.9%) and was associated with older mothers’ age, being married, and higher level of education. The prevalence of timely initiation of complementary feeding (47.9%), dietary diversity (16.0%) and minimum acceptable diet for children between 6 and 9 months (16%) were low. Overall, appropriate complementary feeding practice was low (47.0%) and associated with higher level of mothers’ education and occupation.Conclusions and Global Health Implications: Complementary feeding knowledge and practices were poor among mothers of under-5 especially the non-literate. Reduction of child malnutrition through appropriate complementary feeding remains an important global health goal. Complementary feeding education targeting behavioral change especially among young, single and uneducated mothers in developing countries is important to reduce child morbidity and mortality.Key words: Complementary Feeding • Infant Feeding • Infant and Child Health • Mothers of Under-five Children • PediatricsCopyright © 2017 Olatona et al. Published by Global Health and Education Projects, Inc. This is an open-access article distributed under the terms of the Creative Commons Attribution License CC BY 4.0.
An Analytical Model Predicts Pressure Increase During Waste Water Injection to Prevent Fracturing and Seismic Events
Authors: Jin Lu , Wojtanowicz Andrew K. , Ge Jun 
Published: March 2017

Abstract
In recent years, nationally, an average of 193 magnitude ≥3 earthquakes per year were recorded in 2009–2014, with 688 occurring in 2014 alone, swarms of quakes have continued since then. The increased seismicity is limited to a few areas where there with deep injection of fluids from nearby oil and gas operations. Although most injection operations do not cause earthquakes, numerous field cases have shown steady increase of pressure during the produced water re-injection (PWRI) process. This study provides an analytical method for predicting pressure increase during oily water injection and the rock failure conditions for seismic events.
The model derives from mass balance of oil phase in the oil water mixture while considering the oil capture effects by advection, dispersion and adsorption inside the rock. The time-dependent advancement of trapped oil saturation is determined by solving the governing equation for initial condition of oil-free rock and boundary condition of constant oil concentration in the injection water. Also explained and modeled is the effect of oil saturation on the stick/slip rock resistance and the rock strength.
In the oil capture process, size of the near-well zone of trapped oil increases with time – so does the injection pressure. The model predicts maximum oil saturation, size of trapped oil zone and injection pressure increase vs. time. The model is verified by matching laboratory data from core flooding runs. Results show that even a small oil concentration (&lt;500 ppm) could deposit a 10% residual oil bank around the wellbore that would reduce water injectivity by more than 70% and increase injection pressure by 2000 psi. Moreover, the model confirms field observations of the initial rapid increase of oil invasion and injection pressure. Although the injection pressure may eventually stabilize, the process of internal rock "lubrication" with oil would continue.
Two effects may contribute to the rock slippage during the injection process: (1) the trapped oil droplets reduce internal friction in the rock thus lowering its shear strength; and, (2) water injection increases the pore pressure resulting in lower effective stress of the rock. These effects enhance slippage along existing natural fractures and might also initiate new fractures –causing induced seismicity. Results showed that even low injection rates (300 bpd) could trigger earthquake because injection pressure in the near-wellbore region could easily exceed the minimum principal stress (MPS), facilitating the opening of fractures perpendicular to the MPS direction.
The model provides a useful analytical tool to be coupled with geo-mechanical limitations to assess the risk of long-term injection of large volume of produced water. Mechanism and critical conditions for seismic event are described and a method to find geo-mechanical limitations is outlined.
Implementing an Effective Management of Change MOC System for Upstream Oil and Gas Industry
Authors: Laskar Sandipan 
Published: March 2017

Abstract
The upstream oil and gas industry involves processing high volume of live data during different operations (such as drilling, production, well servicing etc.) and thereby generating high volume of process or procedure changes. It is very important to manage these changes as based on the past incidents in the industry it can be noted that accidents often occurs after changes. Any change that has safety implications should be carefully evaluated, including performing a hazard analysis, before it is allowed. One of the practicable approach in managing these changes is by implementing a Management of Change (MOC) system.
Most companies have policies for management of change, but the implementation and enforcement of these policies can vary greatly. An effective MOC work process includes a review and authorization process for evaluating proposed adjustments to facility design, operations, organization or activities prior to implementation to make certain that no unforeseen new hazards are introduced and that the risk of the existing hazards to employee, the public, or the environment is not unknowingly increased. It also includes steps to help ensure that potentially affected personnel are notified of the change and that pertinent document, such as procedures, process safety knowledge, and so forth, are kept up-to-date.
The main aim of this paper is to address the three basic questions (what? why? and how?) in implementing an effective MOC system. There are more robust MOC program available for the facilities covered under OSHA Process Safety Management program. However the management of change (MOC) work process mentioned in this paper is fit for purpose for upstream oil and gas operation. This paper discusses challenges in implementing MOC system for facilities not covered under OSHA Process Safety Management program and addresses common misconceptions of Management of Change system.
Oil Spill Trajectory Simulation for the Clair Oilfield, Faroe Shetland Channel, United Kingdom Continental Shelf
Authors: Eke Chijioke David , Anifowose Babatunde 
Published: March 2017

Abstract
Oil spills have been identified as a common consequence of the exploration and production of petroleum resources. This is likely to increase with the continuous rise in demand for petroleum and petroleum products. The Clair oilfield holds the largest undeveloped hydrocarbon accumulation in the United Kingdom Continental Shelf (UKCS), indicating its importance to the future of UK production strategy. Significant developments made in oil spill modelling in the last twenty years suggest the need for an updated study on the behaviour of a Clair oil spill. This study aims to design an updated stochastic model for oil spill prediction in the Clair Oilfield in order to provide an understanding of the trajectory, fate and uncertainties of spilled oil at varying environmental conditions. The GNOME software was employed to model the oil spill trajectory in the Faroe-Shetland Channel (FSC) and ADIOS2 for modelling the Clair oil spill weathering processes. "Minimum regret" analysis suggests that spills allowed to persist will cross the Norway/UK boundary line and move further towards the Norwegian coastline. Furthermore, there is the possibility of oil beaching along the coast of the Shetland Island if the oil spill occurs. The weathering models revealed that evaporation will account for about 15% of the oil lost in both summer and winter while dispersion will account for 15% and 30% of the oil lost in summer and winter respectively. Within the 5-day scenario considered the Clair oil forms a meso-stable emulsion resulting in a 100 times increase in the viscosity of the oil and a slight increase in density. Furthermore, airborne benzene concentration evaporated within 15 hours and 6 hours in summer and winter respectively. The results obtained in this study suggest that equipment should be stockpiled as well as mechanical responders for near shore intervention to prevent and tackle possible beaching along the Shetland island coast and the Norwegian coast.
Changing the Safety Culture: Providing an Accident-Free Work Environment
Authors: Simon Flavio 
Published: March 2017

Abstract
This case-study, covering the period 2012 – 2015, describes how a "Change in the Safety Culture" process that took place in workshops which were manufacturing, assembling, and repairing valves used in the fracturing of unconventional reservoirs. The need for action was clearly demonstrated by an unacceptable 2012 Total Recordable Incident Rate of 13.99. A situational assessment, executed by late 2012, showed that the prevailing safety culture was one that accepted as inevitable that "accidents happened, happen, and will continue to happen." Corrective and proactive actions were outlined and implemented in order to change that state of mind. The ultimate and most important key performance indicator (KPI) chosen to monitor the "Change in the Safety Culture" was the rolling 12-month total recordable incident rate (Rol12Mo TRIR). From the period of May 2013 thru the end of 2015 the trend in Rol12Mo TRIR was almost continually downward. The last OSHA recordable injury occurred in November 2014; over the subsequent 13 months in a row, not a single recordable injury was registered.
Combining Advanced Biocide Evaluation and Microbial Monitoring to Optimise Microbial Control
Authors: Johnson Richard J. 
Published: March 2017

Abstract
Microorganisms can cause numerous issues in oil field systems, including microbiologically influenced corrosion (MIC), reservoir souring, biofouling and separation problems. They are often controlled using biocides, however the dynamic nature of both oil field systems and microbial communities means that this is not a set up and leave solution. Therefore, rigorous biocide selection and microbial monitoring must be carried out in tandem to ensure that the treatment chemicals are effective from both a technical and cost point of view.
Microbial monitoring has advanced significantly in recent years, and now incorporates molecular DNA techniques such as quantitative polymerase chain reaction (qPCR) to quantify microorganisms, and metagenomics to identify them. These data however, still need relating back to the methods used to control microbial proliferation in oil field systems.
In this paper a combined approach is presented, with use of an onsite biocide evaluation test apparatus (BETA) to test up to sixteen biocides simultaneously at different dose rates and contact times for many repeated dosages. This is connected to a production or water injection system to realistically simulate pipeline conditions (e.g. temperature, pressure, flow rate, water chemistry, surface materials, etc.) during biocide evaluation. This allows for biocides to be techno-economically ranked under process conditions and may also be used to determine the effects of different biocide regimes on corrosion and pitting rates.
Any changes to the microbial community are detected early using the latest molecular microbiology techniques to ensure that the biocide maintains its effectiveness. This guarantees that any required biocide re-evaluation is carried out when needed, meaning that ineffective biocides are not needlessly dosed, which would increase operating expenditure (OPEX) costs and risks to asset integrity. It also avoids needless biocide re-evaluations where the current regime is working effectively.
An understanding of the type of data from different microbial monitoring tools is important and interpreting this correctly helps to bring a combined approach together, with some of the common pitfalls discussed. By using the most appropriate tools in the microbiologist's tool box for routine monitoring, along with a rigorous biocide evaluation regime, these advances can be used to keep a close control on OPEX along with improving asset integrity and increasing production.
The Impact of Increase in Lateral Length on Production Performance of Horizontal Shale Wells
Authors: Yuan Ge , Dwivedi Priyank , Kwok Chun Ka , Malpani Raj 
Published: March 2017

Abstract
Production drivers including reservoir, completion quality, and number and quality of hydraulic fracture stages influence overall production performance of a well. In an integrated engineering study, all production drivers were assumed to be very similar except for the well horizontal lateral length. Well production rate was calculated with horizontal lateral lengths varying from about 1,000 ft to 20,000 ft with an increment of 1,200 ft. Statistical field data and integrated reservoir-wellbore simulation were compared to draw a comprehensive conclusion. Different domain engineering principles were used to understand the impact of increase in lateral length on production performance of horizontal shale wells.
Vacuum Insulated Tubing Efficiency for Offshore Steam Injection: Case Study from Emeraude Field Congo
Authors: Guillet-Lhermite J. , Robert B. , Bimperling F. , Nkoukou C. , Damour J. , Ollier P. 
Published: March 2017

Abstract
This paper validates the thermal efficiency of Vacuum Insulated Tubing (VIT) for offshore steam injection application on Emeraude Field (Congo). It includes field measurement of thermal dissipation prior to VIT installation, steam injection logging tool interpretation, thermal losses modelling of offshore steam injection, and well monitoring data post-installation. It is concluded that VIT improved steam quality from 35% up to +95%, leading to significant steam generation cost savings and overall EOR efficiency improvement.
PERENCO/CONGOREP started offshore steam injection in Emeraude in April 2010 from the new MOAB platform, with 4 steam injector and 9 producer wells. The purpose of the project was to pilot offshore steam injection, using an inverted 5 spot pattern on the R2 reservoir. In 2013, steam PLT runs and temperature monitoring measured that steam quality downhole was only 35%, meaning that 65% of latent heat was lost by thermal conduction and sea water convection along conductor pipe.
Following these observations, thermal model simulation was performed, which confirmed the severity of thermal losses along the submerged casing section (60m water depth at MOAB location). Moreover, shallow water bearing reservoirs were showing temperature increases in neighboring production wells, revealing unexpected sub-surface thermal losses. A remedial option was identified as the implementation of vacuum insulated tubing on steam injectors. PERENCO and MAJUS collaborated to take advantage of a workover opportunity in July 2015, and fast-tracked VIT installation using 3″1/2 ID VIT tubings down to 308m.
Steam injection was resumed immediately, and we observed a positive insulation effect in neighboring wells. With only 0.8t/hour steam injection, EMM-511 well demonstrated the same thermal impact as a 2t/hour non-insulated injector. Steam savings allowed the boiler to be run on fuel gas only, reducing the need for extra fuel oil consumption. From September 2015, decreased water cuts were also noticed in neighboring production wells, unlocking an additional bottleneck. New steam PLT runs have not been made yet, but these indirect observations confirmed thermal loss predictions of +95% steam efficiency with VIT as predicted by thermal modelling.
CONGOREP will continue to adapt Thermal EOR strategy to respond to offshore conditions. By implementing MAJUS vacuum insulated tubings on the EMM-511 well, we demonstrated the fundamental impact of thermal insulation in offshore environment. By increasing steam quality up to +90%, we significantly reduced fuel oil consumption, improved thermal efficiency, and reduced water breakthrough on producing wells.
VIT technology has been field proven for offshore steam injection with increasing steam efficiency and overall thermal efficiency. Thermal simulation predictions were validated by field monitoring and positive impact was demonstrated on neighbouring wells.
Rock-on-a-Chip Devices for High p, T Conditions and Wettability Control for the Screening of EOR Chemicals
Authors: Wegner J. , Ganzer L. 
Published: March 2017

Abstract
In this paper, we present a new generation of micromodels that will significantly improve the investigation of "Enhanced Oil Recovery (EOR)" processes under in-situ reservoir conditions (p, T). The micromodels presented will be used as an integral part of the surfactant selection process and are considered a useful tool among phase behavior testing and core floods.
The micromodel developed is a sandwich of different materials; Glass-Silicon-Glass (GSG). The porous structure is completely dry etched through the silicon which results in a transparent micromodel. The GSG - micromodels presented in this study show several advantages over "conventional" micromodels made of silicon, PDMS or glass: (1) they are transparent, hence, enable more flexible image gathering, (2) permit the construction of small pore-throats and complex flow geometries and (3) facilitate the investigation of transport processes at high p, T.
The wettability of the micromodel is controlled using nanotechnology based coatings which are critical to run micromodel flooding experiments under predefined conditions. The nanocoating technology can be best described by densely packed molecular piles bound to the surface via strong covalent bonds. Therefore, excellent hydrolytic, chemical and thermal stability of the nanocoatings is observed.
The paper discusses micromodel construction, surface modification and experimental setup and will show how the microfluidic technology can be used to rapidly screen suitable surfactant solutions for "Enhanced Oil Recovery (EOR)" applications.
Results show that microfluidic technology give detailed pore-level insights into multi-phase displacement of oil by surfactant solutions including percolation of emulsions. Further, if applied they can accelerate the surfactant screening process and considerably reduce the amount of required core floods. Hence, microfluidic surfactant screening be considered an integral part of the surfactant solution selection process in the future.
A Case Study of Comprehensive Field Development Design for a Tight Gas Chalk-Reservoir in North Sea
Authors: Ansari Arsalan , Alklih Mohamad , Ghosh Bisweswar 
Published: March 2017

Abstract
In all probability, the petroleum industry is faced with a number of enormous challenges resulting from the declining oil prices such as high abandonment and new wells construction costs, low sweep efficiency, harsh environments etc. These challenges can be met by designing a long term development plan of a petroleum prospect, ensuring maximum recovery without sacrificing the safety standards. This work describes a multicomponent and strategic development plan designed for a tight gas reservoir, starting from formation evaluation to drilling-completion and economic analysis in addition to the environmental issues that must be considered in advance.
The field is principally a gas condensate field, where the reservoir is mainly Chalk with an average porosity of 27% and average permeability of 0.1mD with 65% water saturation. The reservoir pressure (5960 psia) and dew point (5940 psia) being very close, the reservoir is close to saturation pressure and gas condensate is expected to form immediately on commencing production. PVT studies indicated that the critical condensate saturation will not be reached which in turn means that it will never be mobile or recoverable with reservoir pressure decline. Given the fact that the water drive is rather weak, pressure maintenance methods will be needed to avoid the condensation of gas within the reservoir.
Based on petro-physical evaluation, our team was able to construct a static reservoir model using Petrel Software and the team suggested three different development scenarios consisting of horizontal and multilateral wells of various configurations. Based on the development strategies, a dynamic model is constructed for each scenario to compare the techno-economic feasibility and selection of the most optimum strategy. It was found that the field would be economically viable to produce for a time period of 50 years and the simulation results indicate that an ultimate recovery of 69-76% was achieved if water injection is applied from year-1 onwards. Moreover, the highest recovery factor of 76% is achieved with scenario-B as it has a five spot pattern with 8 vertical injection and 3 multilateral production wells. In addition, the most delayed water breakthrough is achieved in this scenario that occurs after 2.5 years. Moreover, it was also observed that the pressure maintenance was 100% effective in scenario-C as the reservoir pressure increased as a result of increasing the water injection rate rather than increasing the sweep efficiency. However, for the other scenarios, the reservoir pressure drops but not below the critical value.
Finally, a cumulative gas production of 389-424 MMMSCF was observed along with a gas production rate of 8.61-24.7MMSCF/day giving a cumulative net present value of $890,000 with a payback period of 5 years, indicating that the project is economically viable after 50 years.