bluuebunny/crossref_metadata_2025_split huggingface dataset:
Facial Skeletal Morphology in Growing Children with Pierre Robin Sequence
Authors: Shen Yoshi F. , Vargervik Karin , Oberoi Snehlata , Chigurupati Radhika 
Published: December 2010

Objective The purpose was to compare the jaw size, jaw relationship, and facial proportions of children with nonsyndromic Pierre Robin sequence with children with nonsyndromic or isolated cleft palate. Design This is a retrospective cohort study comparing radiographic findings in children with Pierre Robin sequence or isolated cleft palate at two time intervals: ages 4 to 7 years (T1) and ages 10 to 13 years (T2). Linear and angular measurements were obtained using cephalograms; the cephalometric values were compared with unpaired t tests, assuming unequal variances. Setting The study was conducted at the Center for Craniofacial Anomalies at the University of California, San Francisco. Patients The sample included 13 children with Pierre Robin sequence and 14 children with isolated cleft palate who were followed at University of California, San Francisco, craniofacial anomalies clinic during the period from 1971 to 2007 and met the inclusion criteria. Main Outcome Measures The outcome measures were mandibular length, maxillary length, and sagittal jaw relationship in Pierre Robin sequence and isolated cleft palate children at T1 and T2. Results During early childhood (T1: 4 to 7 years), mandibular length (Co-Gn) was similar in both Pierre Robin sequence and isolated cleft palate groups, as was the maxillary length (Co-A). In older children (T2: 10 to 13 years) mandibular length was significantly shorter in the Pierre Robin sequence group compared with the isolated cleft palate group (difference = 10.9 mm, p = .009). Maxillary length in Pierre Robin sequence and isolated cleft palate groups was similar at T2 but significantly shorter in comparison to age-matched norms with a difference of 14.5 mm ( p = .037) for Pierre Robin sequence and 12.4 mm ( p = .045) for isolated cleft palate. Children with Pierre Robin sequence did not show a sagittal jaw discrepancy due to a proportionate deficiency in maxillary and mandibular length; whereas, children with isolated cleft palate showed a greater sagittal jaw discrepancy due to normal mandibular length and deficiency in maxillary length. Conclusion Our study confirms the findings of some previous studies that suggest that children with nonsyndromic Pierre Robin sequence have a proportionate retrusion of the maxilla and mandible, resulting in a convex facial profile by early adolescence.
Development of a Methodology to Predict Solids Concentration Profile Along the Time During Pumps-off Periods
Authors: Pinto G. H. , Gandelman R. A. , Martins A. L. 
Published: December 2010

Abstract
One of the main functions of drilling fluids is to transport solids generated by the bit to the surface. Gelation is an important and desirable phenomenon once it avoids solids sedimentation during pumps-off periods. However, when circulation is resumed, an extra energy is required to break gel and, consequently, bottom–hole pressure peaks are observed, causing detrimental effects when fracture pressure is reached. On the other hand, gelled fluids may not avoid some heavier and/or larger particles to settle. The understanding of how particles sediment in gelled fluids is a very important task to predict solids concentration profile during and after pumps-off periods.
This work presents the development of a methodology to predict particles sedimentation in gelled fluids and pressure peaks when circulation is resumed.
Microbiologically Influenced Corrosion of Electrical-Submersible- Pumping- System Components Associated With Acid-Producing Bacteria and Sulfate- Reducing Bacteria: Case Histories
Authors: Adams D. L. 
Published: December 2010

Abstract
Microbiologically Influenced (Induced) Corrosion, MIC, can cause corrosion that may go unrecognized or misdiagnosed in oil production.
The end result of this corrosion phenomenon can be costly damage to down-hole equipment and other well components; leading to lost production and to premature failure of the electrical submersible pumping system (ESP) equipment, as well as other down-hole components.
A better understanding and proper diagnosis of this issue could reduce the corrosion damage and the cost associated with this corrosion phenomenon.
This paper is a presentation of case histories of this corrosion phenomenon experienced around the world.
Pore-Type Determination From Core Data Using a New Polar-Transformation Function from Hydraulic Flow Units
Authors: Rodolfo Soto B. , Arteaga Duarry , Martin Cintia , Rodriguez Freddy 
Published: December 2010

Abstract
A new sigmoidal function from polar transformation enables more accurate identification of pore types in fractured/vuggy reservoirs. The function is based on a polar transformation that separates the pore systems into two regions—matrix systems and fracture/vug systems—on the basis of hydraulic properties, reservoir quality index (RQI), flow-zone index (FZI), and normalized porosity. The polar transformation exhibits a hyperbolic distribution for intergranular/intercrystalline pore sample types at the point where they deviate from the trend so that we can identify pore types more accurately. Our new function has been validated from image log data from wells of Lagomar and/or Lagomedio fields and core data from different fields around the world, and we are certain that it will be of great help to the geoscientist when doing a reservoir characterization.
Hydraulic Analysis of Gas-Oil-Sand Flow in Horizontal Wells
Authors: Bello O. , Udong I. , Falcone G. , Teodoriu C. 
Published: December 2010

Abstract
The limited knowledge and understanding of three-phase gas-oil-sand flow behaviour and transport processes has hampered the design, safe operation and project profitability of horizontal wells deployment in unconsolidated hydrocarbon reservoirs. This work presents analytical uations for calculating pressure drop characteristics and optimal flow rate to avoid sand particles deposition and accumulation in a horizontal production well under steady state conditions. The analysis is based on multiphase transport fundamentals and mechanics of particle motion in three-phase flow. The pressure gradient results predicted by the proposed model show a satisfactory agreement with a published model. A sensitivity study is then made (after model validation) using the new model to investigate effects of operating, design and system parameters on pressure gradient and optimal transport velocity under wide-ranging conditions found in practice. The potential advantages of the new methodology are also reported.
The Marlim Field: Incorporating Time-Lapse Seismic in the Assisted History Matching
Authors: de Brito D. , de Moraes R. , Emerick A. 
Published: December 2010

Abstract
History matching is one of the most important and time consuming tasks in reservoir simulation. In traditional history matching approaches engineers attempt to honor production data by manually modifying their simulation models. Even though such approaches are being gradually replaced by assisted history matching methods the engineer is still responsible for choosing which simulation model parameters must be modified. On the other hand optimization algorithms available in assisted history matching tools allow changing parameter values automatically and also to consider 4D survey data in the objective function. Transmissibility multipliers associated to regions located between wells are among the most traditional simulation model parameters used for history matching purposes. Such procedure is very efficient in order to match water production data, but usually leads to transmissibility maps which have no geological meaning.
This paper describes the results of the assisted history matching study of Marlim Field, the biggest offshore field in Brazil. The assisted history matching presented here included both production and 4D seismic. The seismic information was used qualitatively and quantitatively, i.e., to delimitate regions associated to transmissibility multipliers and also in the objective function itself. The assisted 4D history matching was carried out with a commercial history matching tool, which allows the synthetic seismic calculation.
The production history data of most part of the wells was matched with similar accuracy one would expect to obtain through a careful and time consuming manual history matching approach. However the total elapsed time achieved here was orders of magnitude smaller. In addition the shape of the regions associated with model parameter values was totally supported by 4D seismic information.
It turns out even with the aid of assisted history matching tools, the quality of the results strongly depends on adequately choosing which simulation model parameters must be modified in order to match the production data. Once 4D seismic data can give a realistic picture concerning reservoir fluid replacement it can also highlight preferential permeability pathways. The results of the present study have shown these indications can be very helpful to delimitate regions with history matching purposes that have geological significance.
A New Methodology for PVT Sampling Optimization and Producibility Determination From Nuclear Magnetic Resonance
Authors: Pazos J. , Morales O. , Goddyn X. , Angel J. 
Published: December 2010

Abstract
The Eden Yuturi field discovered in 1996 is located in the Amazonian basin and holds several oil bearing geological units belonging to the Cretaceous. T and U sandstones are the most prolific and belong respectively to Albian and Cenomanian. They are characterized by a cyclic sequence of shales and sandstones whose deposition is driven by sea level changes. Their facies range from tidal-fluvial influenced to shallow marine. The 300 ft of U and T sands exhibit various oil qualities and compositional gradients so far poorly characterized. Another sandstone, M1 is a low resistivity pay and challenges regularly petrophysical evaluation. PetroAmazonas, in an effort to characterize the reservoir fluids and to strengthen the reservoir model, decided to initiate a sampling campaign with the EYXX well. An innovative workflow was put into place to optimize the PVT sampling and predict the producibility for reservoir. Nuclear magnetic resonance (CMR) & modular dynamic formation tester (MDT) are part of the solution put into place. NMR enables an almost immediate determination of crude oil viscosity at down hole condition to locate accurately MDT PVT bottles. CMR viscosity determination revealed, after PVT analysis delivery, been extremely accurate and validated for the whole field. Additionally magnetic resonance pore size distribution was tie in mathematically to rock types and a numeric expression of relative permeability derived, based on available core data in the field. Finally, nuclear magnetic information combined with pressure data, enabled a very accurate producibility prediction for each sands. Sampling was also successful and correlation between optical density of the optical fluid analyzer & real fluid viscosity was established. An advanced nuclear magnetic profiling was also inaugurated showing oil in the well known low resistivity M1 sands.
Reducing Formation Damage in Open Hole Standalone-Screens (OH-SAS) Completion for New Wells
Authors: Mohamad W. A. , Wahba M. A. , Jadid M. 
Published: December 2010

Abstract
The use of drill-in-fluid (DIF- sized salt system treated with enzyme breaker) during drilling and completion operations in the reservoir section contributed to the improvement in wellbore productivities especially desired in open hole completion where sand control using stand alone screens were applied. The mud system was designed to create a competent wellbore mud cake that was broken down by enzymes thus enabling it to flow back during production without any requirement for extensive clean-up job.
The successful application of this mud system in simplified sand control completions in newly drilled and completed wells has enabled PCSB to establish this sand control technique as an economically viable option. The high well productivity indices and the ease of well clean-up during early production has been observed in many newly completed wells with OH- SAS completions.
The early success of this sand control philosophy with the use of DIF for drilling the reservoir section, is indicated by sustained production of 7,000-8,000 bopd from the two wells in an oil field since early 2007. The high productivity indices of over 100 bpd/psi has enabled the wells to be produced at low drawdown pressures thereby preventing slumping and production of sand onto the screen. This can be concluded from the continuing high flowing tubing head pressures in both wells.
This paper highlights the successful use of DIF in contributing to the much improved well productivities giving some highlights of the production performances of the wells completed with OH-SAS to date compared with cased hole gravel packed (CHGP) wells as was previously practiced.
An Equation to Predict Two-Phase Relative Permeability Curves in Fractures
Authors: Chimá A. , Chávez E. , Calderón Z. 
Published: December 2010

Abstract
E. S. Romm in 1966 (Romm 1966) proposed an equation to calculate the relative permeability curves in fractured systems based on experimental results. His research concluded that relative permeability is a linear function of saturation (krw = Sw, krnw=Snw). Currently most fractured reservoir simulators use E. S. Romm's equation to estimate relative permeability curves in fractures. Later in 1994, D. A. Pieters and R. M. Graves (Pieters & Graves 1994) demonstrated experimentally that relative permeability curves are not a linear function of saturation. In this work, we use the concepts of shell momentum balance (Bird, Stewart & Lightfoot 2002), the equation of change for isothermal systems, Newton's law of viscosity and Darcy's law in order to derive an analytical equation to calculate relative permeability curves in fractured systems for two phase flow. These proposed equations assume gravitational segregation between the two phases (Rossen & Kumar 1992), Newtonian fluids, incompressible fluids, Laminar flow, steady-state and constant temperature.
These proposed equations in this paper could be applied to calculate relative permeability curves in two-phase flow systems in fractures. Further, the two-phase relative permeability curves can be used to predict the behavior of naturally fractured reservoirs. This work also includes a comparison of the calculated data between E. S. Romm's equation, Pieters and Graves's Laboratory data and the equations proposed in this paper.
As a result of this research we demonstrated analytically that relative permeability curves in two-phase flow in fractures are not a linear function of saturation. Also we confirmed the non linearity of the fracture's relative permeability curves using a reservoir and fluid data with the proposed equation.
Monitoring and Optimizing Oil Fields by a Real-Time Production Operation (RTPO) System
Authors: Dutra Thiago , Machado Leonardo , Rodriguez Miguel , Almeida Inaê , Montanha Breno , Manzali Marcelo , Dinis Marcelo , Carbone Leonardo , Fabricio de Souza Marcos , Herdeiro Marco 
Published: December 2010

AbstractCompanies worldwide have been investing in solutions to provide production and cost optimization. As a result, real-time operation systems have been used to help in achieving these objectives. This paper provides a description of the use of real-time operation systems and how the integration of their disciplines made it possible to optimize production and costs for oil and gas fields.Working as an integrated multi-disciplinary approach, real-time production-operation systems enable the maximization of oil and gas production of assets at lower costs, while providing a better understanding of the current scenario of oil and gas fields. To obtain these improvements, some characteristics to be considered are described below. The consolidation of the whole asset- production data into a single system provides mechanisms to monitor, analyze, and control oil and gas fields. These data are automatically uploaded to the system to minimize manual efforts, making more time available for process analyses. To avoid spurious data, an automatic validation mechanism for the data acquisition process was developed. In addition to production monitoring and the enhanced data quality, historical data, alarms, and statistic tools are used to improve the data analysis and interpretation process. The solution also enables the online well-production prediction using a neural-networks model as well as the integration with a reliable system to identify, quantify, and classify production losses. Because the information is displayed in an online system, the same data at the same time are available for access from different users.The use of real-time production-operation systems enables strategies for asset managers to make faster decisions and provide better solutions to asset operational issues.These outcomes are achieved as a result of integrated production, losses, and process-parameters information, as well as the acquisition process of validated data and the availability of tools for analysis and interpretation.
Study for Improving the In-Situ Combustion of Venezuela Extra-Heavy Crude Oil Using Unconventional Additive
Authors: Mendoza R. A. J. , Perozo H. , Oliveros D. , Reyes N. 
Published: December 2010

AbstractVenezuela has considerable heavy oil reserves; in consequence the evaluation of the potential technologies to be applied for its exploitation is required. Heavy and extra heavy crude oil reservoirs are produced initially using its primary energy. However, depending on the viscosity the production in other reservoirs will be directly by enhanced thermal processes. One of the thermal technologies that have been studied for more than three decades worldwide is the in situ combustion process. In the last ten years the use of additives has been important to promote the upgrading of the produced oil. Combustion process with additives has shown some advantages with respect to conventional combustion: (1) oil production increases, (2) faster combustion front, and (3) higher temperatures during the combustion. The main goal in the present work is to evaluate an additive for in situ combustion process in order to enhance it. Inexpensive waste stream was used as additive for upgrading the produced crude oil. The experimental methodology used is based first; in to introduce the additive in 2/3 of the total of the porous media, then the void space into the cell is completed with porous media without additive. After, the system is preheating, following by air injection applied into the porous media during the entire combustion test. Once the combustion front will face the additive, it acquires faster velocities and the front stability was reached quicker than during conventional combustion test. The results obtained with the additive shows the production of lighter compounds. It is a promising opportunity to exploit and to produce the Venezuelan heavy crude oil reserves. In consequence, it will be possible to get oil with more value in the market.
Integrated Optimization System for Short-term Production Operations Analysis
Authors: Rebeschini Jordani , García Alejandro , Lima André , Purwar Suryansh , Carbone Leonardo , Dinis Marcelo , Herdeiro Marco Antonio 
Published: December 2010

AbstractField-performance maximization is subject to an optimum tuning of the operations downstream in the reservoir. This single task is based on field-parameters surveillance, such as reservoir pressure, tubing and pipeline conditions, the equipment's capacity and availability. The quicker the engineer reacts to a change on these parameters, the quicker a production would be optimized or a loss minimized. This work addresses this problem by providing a real-time production-operations monitoring system implemented for an offshore field in Brazil.The system is based on a workflow that integrates the most recent well models updated via well tests, current platform conditions, and gathering network models, and is designed to provide the optimal operational settings, including: a) production-processing train alignment, b) artificial gas-lift distribution among wells, c) choke opening, and d) compressor operating pressures. This workflow is accomplished by the user via an interactive web interface, where information is accessed, updated, and validated in real time.The results are reflected in added barrels as result of a constant field-production improvement and improvement in data management tasks, such as data capture, information QA/QC, and models updates, with significant reductions in time.The solution has proved to be a useful tool for the users in adjusting the operational settings on a daily basis or as needed in the presence of unexpected events, constantly optimizing the field production with its most-updated information.This work was designed by production engineers and can also be used by any asset member to simulate the impact of planned or non-planned scenarios that can potentially change the operational guidelines of the day or a single period. Institutionalization of knowledge is a characteristic of this system, which makes it easy to use and to understand.
Pressure-Transient Analysis for Naturally Fractured Reservoirs With Transition Period Before and After the Radial-Flow Regime
Authors: Escobar F. H. , Martinez J. A. , Cantillo J. H. 
Published: December 2010

Abstract
It is expected for naturally occurring formations that the transition period of flow from fissures to matrix takes place during the radial flow regime. However, depending upon the value of the interporosity flow parameter, this transition period can show up before or after the radial flow regime. First, in a heterogeneous formation which has been subjected to a hydraulic fracturing treatment the transition period can interrupt either the bilinear or linear flow regime. Once the fluid inside the hydraulic fracture has been depleted, the natural fracture network will provide the necessary flux to the hydraulic fracture. Second, in an elongated formation, for interporosity flow parameters approximated lower than 1×10-6, the transition period takes place during the formation linear flow period. It is desirable not only to appropriately identify these types of systems but also to complement the conventional analysis with the adequate expressions to characterize such formations for a more comprehensive reservoir/well management.
So far, the conventional methodology does not account for the equations for interpretation of pressure tests under the above two mentioned conditions. Currently, an interpretation study can only be achieved by non-linear regression analysis (simulation) which is obviously related to non-unique solutions especially when estimating reservoir limits and the naturally fractured parameters. Therefore, in this paper, we provide and verify the necessary mathematical expressions for interpretation of a vertical well test in both a hydraulically-fractured naturally fractured formation or an elongated closed heterogeneous reservoir. The equations presented in this paper could provide good initial guesses for the parameters to be used in a general nonlinear regression analysis procedure so that the non-uniqueness problem associated with nonlinear regression may be improved.