bluuebunny/crossref_metadata_2025_split huggingface dataset:
Transcriptomes in Healthy and Diseased Gingival Tissues
Authors: Demmer Ryan T. , Behle Jan H. , Wolf Dana L. , Handfield Martin , Kebschull Moritz , Celenti Romanita , Pavlidis Paul , Papapanou Panos N. 
Published: November 2008

Background: Clinical and radiographic measures are gold standards for diagnosing periodontitis but offer little information regarding the pathogenesis of the disease. We hypothesized that a comparison of gene expression signatures between healthy and diseased gingival tissues would provide novel insights in the pathobiology of periodontitis and would inform the design of future studies.Methods: Ninety systemically healthy non‐smokers with moderate to advanced periodontitis (63 with chronic periodontitis and 27 with aggressive periodontitis) each contributed at least two diseased interproximal papillae (with bleeding on probing [BOP], probing depth [PD] ≥4 mm, and attachment loss [AL] ≥3 mm) and a healthy papilla, if available (no BOP, PD ≤4 mm, and AL ≤2 mm). RNA was extracted, amplified, reverse‐transcribed, labeled, and hybridized with whole genome microarrays. Differential expression was assayed in 247 individual tissue samples (183 from diseased sites and 64 from healthy sites) using a standard mixed‐effects linear model approach, with patient effects considered random with a normal distribution and gingival tissue status considered a two‐level fixed effect. Gene ontology analysis classified the expression patterns into biologically relevant categories.Results: Transcriptome analysis revealed that 12,744 probe sets were differentially expressed after adjusting for multiple comparisons (P <9.15 × 10−7). Of those, 5,295 were upregulated and 7,449 were downregulated in disease compared to health. Gene ontology analysis identified 61 differentially expressed groups (adjusted P <0.05), including apoptosis, antimicrobial humoral response, antigen presentation, regulation of metabolic processes, signal transduction, and angiogenesis.Conclusion: Gingival tissue transcriptomes provide a valuable scientific tool for further hypothesis‐driven studies of the pathobiology of periodontitis.
Effect of Microthreads and Platform Switching on Crestal Bone Stress Levels: A Finite Element Analysis
Authors: Schrotenboer Jason , Tsao Yi‐Pin , Kinariwala Vipul , Wang Hom‐Lay 
Published: November 2008

Background: The aims of this study were to investigate the effects of implant microthreads on crestal bone stress compared to a standard smooth implant collar and to analyze how different abutment diameters influenced the crestal bone stress level.Methods: Two‐dimensional finite element imaging was used to create a cross‐sectional model of an implant (5‐mm platform and 13 mm in length) placed in the premolar region of the mandible. The two tapered implant models consisted of one with microthreads at the crestal portion and the other with a smooth neck. The implant model was reverse‐engineered to resemble a commercially available microthread implant. Abutments of different diameters (4.0 mm: 20% platform switching; 4.5 mm: 10% platform switching; and 5.0 mm: standard) were loaded with a force of 100 N at 90° vertical and 15° oblique angles. Finite element analysis was used to analyze the stress patterns in bone, especially in the crestal region.Results: Upon loading, the microthread implant model had 29% greater stress (31.61 MPa in oblique and 9.31 MPa in vertical) at the crestal bone adjacent to the implant than the smooth‐neck implant (24.51 and 7.20 MPa, respectively). When the abutment diameter decreased from 5.0 to 4.5 mm and then to 4.0 mm, the microthread model showed a reduction of stress at the crestal bone level from 6.3% to 5.4% after vertical loading and from 4.2% to 3.3% after oblique loading. The smooth‐neck model showed a reduction of stress from 5.6% to 4.9% after vertical loading and from 3.7% to 2.9% after oblique loading.Conclusions: Microthreads increased crestal stress upon loading. Reduced abutment diameter (i.e., platform switching) resulted in less stress translated to the crestal bone in the microthread and smooth‐neck groups.
Hybrid 5-way Dune Statics Solution for an Abu Dhabi Land 3D Seismic Survey
Authors: Ajlani Ghiath , Mahgoub Mohamed , Leveque Andre , Haddabi Ali 
Published: November 2008

Abstract
ADNOC recently acquired a large land vibroseis 3D seismic survey in an area with steep and up to 300 meters AMSL high sand dunes interrupted by numerous sabkhas as shown in Figure 1. Additionally, each acquisition live patch covered a large 32 km2 6400 channels area with dense 12.5 × 12.5 meters bin size. These conditions dictated the need for innovative and effective statics solutions in acquisition and processing that can handle the large and complex long and short wavelength statics consistently throughout the survey.
In order to understand the in-dune sand velocities in the survey area an extensive uphole drilling program was executed in a regular grid of 70 meters sabkha-intermediate dunes upholes and 150 meters high sand dunes holes down to the base of sand. Using the uphole data, a 3D dune and near surface velocity model was constructed covering the entire survey area. Subsequently, automatic refraction statics first break picks with manual picking QC were merged with the 3D dune model in addition to the initially applied elevation statics in a hybrid integrated approach to calculate final statics.
For the longer wavelengths, a near offset reflection static flattening scheme was applied by picking and gridding a shallow 3D horizon on the geophone MSL stack and creating a smoothed and normalized low/high frequency volume in the shot and receiver domains. Additionally, two runs of optimized short wavelength residual statics were then applied at subsequent stages of the processing flow.
As a result of this 5-way hybrid statics approach, effective and high quality solution of the severe dune, sabakha and near surface velocity variations was implemented successfully.
Horizontal Well Performance Optimization using Linearized Inflow Control Devices
Authors: Krinis Dimitrios , Al-Dawood Naseem , Soremi Yinka 
Published: November 2008

Abstract
This paper presents two case studies that evaluate the impact of the Linearized Inflow Control Device (LICD) on horizontal wells performance in a Saudi Aramco giant carbonate field. Linearized Inflow Control Devices regulate inflow by diverting production either through spiral channel or through pre-determined choked ports. The net effect is to restrict high productivity segments while increasing flow in the low productivity segments. LICDs are being utilized as part of an initiative to use custom-fit technologies to optimize horizontal well performance, thereby improving sweep and recovery efficiency.
The objectives of drilling horizontal wells in this field are to prolong dry oil production, increase reservoir drainage and efficiently sweep oil beneath the gas caps and/or behind the flood front. Horizontal wells, however, have been faced with the challenge of producing reservoir fluids through non-uniform inflow from reservoir heterogeneities/pressure variations along laterals, presence of fractured zones and frictional effects along the wellbore. The non-uniform inflow promotes early water/gas break-through, leading to short-lived wells and unfavorable sweep.
As a solution to this challenge, LICDs have been installed in selective horizontal wells. Results to date show remarkable improvement in well performance, where gains in oil production with controlled water production has been achieved. Long-term reservoir simulation results also showed considerable recovery increase in the linearized case over the non-linearized case. This paper presents the evaluation and results of linearized ICD technology, and how it became a game changer in this field development.
Interface Management
Authors: Collins R. , Durham R. , Fayek R. , Zeid W. 
Published: November 2008

Abstract
The UAE has been progressively expanding its oil and gas production for the past decades and has ambitious plans to continue to do so. However, as the projects have become larger and more complex and some of them are extensions to existing facilities, there has been a vast increase in the array of interactions between the respective projects, the existing facilities and the infrastructure and third parties upon which they both depend and on which they impact. These interactions, if not managed effectively, can lead to major difficulties at both macro and local planning level.
Foster Wheeler, an engineering, procurement and construction contractor (EPC), is active in design and execution of major projects throughout the Middle East region and globally and is providing management services to several of the larger projects in Abu Dhabi; at Habshan, Asab and Ruwais. This paper outlines some of the challenges with key interfaces and interdependencies that were encountered in Abu Dhabi, together with the actions taken to manage them during the implementation of these large and complex projects.
Working closely with the GASCO management team, interfacing activities with eminent parties such as ADNOC for HSE studies approvals, the Supreme Petroleum Council to obtain project approvals, and working with ADNOC management, other ADNOC operating companies, EPC contractors, ADWEA, municipalities, foresty commission, local highways authorities, the Petroleum Port Authority at Ruwais, Port Zayed at Abu Dhabi, Critical National Infrastructure Authority, Police Authority etc, have all had their challenging moments. This experience has provided us with: An extensive insight into the way in which these interactions work here in Abu Dhabi andExcellent lessons learned regarding the critical success factors in making these interactions function well
In summary, this paper provides a useful case study which demonstrates that good interface management is vital to the successful delivery of large, complex projects, especially in today's busy contracting environment in the Middle East.
Novel Approach to High Water Cut Measurement in a Mature Oil Field
Authors: Sandau C. , Waddell J. , Berthelet T. 
Published: November 2008

Abstract
Canadian Nexen Petroleum Yemen (CNPY) produces two million barrels of fluid per day at 95 percent watercut from the Masila Block (Block 14) in Yemen. Asset development decisions are based on numerous factors, one of the most important being the amount of oil produced from a well. With increasing oil price, it is becoming economically feasible to produce wells at significantly higher watercuts. The analytical variability of volumetric methods used in Block 14 to measure watercut restricts the accuracy and precision of these measurements. The authors developed a robust and reproducible water cut determination method for this mature petroleum asset based on gravimetric measurement of oil and water phases.
The gravimetric measurement approach follows the volumetric method procedures but uses a balance to weigh the oil or water fractions. To keep consistent with historical reporting of oil production, the density of each phase is then used to correct the values to a volume basis.
The methodology outperforms the volumetric determination of water cut by being more reproducible (better precision) and allowing for the accurate measurement of water cuts up to 99.5 percent. In side by side comparison of the gravimetric and volumetric methods at 99.5 percent water cut, the gravimetric methodology showed a five fold increase in accuracy. In addition, the gravimetric method provides six to ten times better precision in the measurement of watercut on representative field samples compared to the volumetric methodology. The program at Block 14 investigated the use of a reference calibration matrix standard as a data quality system to establish the detection limits of the methodology and to institute a testing procedure to monitor laboratory performance.
The increased accuracy and precision in watercut measurement gives reservoir engineers the confidence to make economic decisions on well viability to maximize overall project NPV.
A Successful Process for Embracing Uncertainty and Mitigating Risk -From Geological Understanding to Development Plan Optimization of a Saudi Complex Reservoir
Authors: Elrafie Emad , Zabalza-Mezghani Isabelle , Abbas Tariq , Kozlov Yakov , Craghill Roderick 
Published: November 2008

Abstract
Integrated reservoir studies aim at synergizing all disciplines to form a reservoir understanding and best strategy to field development. Handling uncertainty and risk using probabilistic approach is a challenge since it becomes quickly overwhelming.
This paper describes the approach used to handle uncertainty and risk in the Saudi Aramco Event Solution process. This approach lies in between the conventional deterministic approach where the team agrees on one realization and the probabilistic approach where a whole family of realizations is covering all possible outcomes.
Here, throughout the process of understanding the reservoir, the team agrees on the most-likely value for all input variables, and set ranges of uncertainty for each of them. Testing the effect of these boundaries on the static models and OOIP, history matching quality or prediction strategy efficiency leads to discriminate the critical factors.
This discrimination helps to narrow down the number of uncertain factors and their ranges from one stage of the study to the next one and focuses on what really matters according to the study objective. The critical controllable factors are tuned to optimize production performances. Information plans are set to narrow down the uncertainty range on the uncontrollable factors.
Finally, a list of risks is stated for risk assessment. Potential risks are identified through four categories: level, probability, urgency and manageability, to which high, medium, and low values are assigned. Risks scoring 3 or 4 on the risk scale (meaning high in 3 or 4 categories) are flagged and mitigation plans are addressed.
This paper presents an application of this process on a Saudi complex oil reservoir, which results in developing a clear understanding of the critical uncertainties, project risks, and the agreed development plan, information plan and mitigation plan.
Commercial ASP Flood Test in Daqing Oil Field
Authors: Jiecheng Cheng , Dianping Xu , Wenguang Bai 
Published: November 2008

Abstract
Alkali-Surfactant-Polymer (ASP) pilot test with small well spacing and the test with enlarged well spacing for commercial ASP flood are successful in Daqing Oil Field, demonstrating ASP process can greatly enhance oil recovery and bring more economic benefits. However, there are also some problems appearing during ASP flood test, such as serious scale, produced fluids hard to be disposed, and with the well spacing enlarged these two disadvantages might be worse. Therefore, a commercial ASP field test is performed to study performances of ASP flood, scaling characteristics and processing techniques of produced fluids. The five-spot well pattern is adopted in test area, including 18 injection wells and 29 producing wells, and chemical agent, sodium alkylbenzene sulfonate, is produced by Daqing Oil Field. On the basis of laboratory core flood, the formula has been optimized, which can create ultra-low interfacial tension with wide ranges and favorable emulsification. The studies, laboratory core test and numerical simulation, show that ASP system can improve oil recovery 20% more than water injection. At present, polymer injection is following the ASP flood, and the performances from commercial ASP flood are different from those of previous ASP flood. When water cut is slight declined, the injectivity will be greatly increased; the scale is serious for ground equipment, but it is rarely found in the borehole. With the surfactant produced, oil and water separation of produced fluid becomes much harder. The oil recovery enhanced by commercial ASP flood is less than ASP pilot test. If the well spacing is shortened, surfactant performance further improved and ASP system is more optimized, oil recovery efficiency will be further enhanced.
"SIMOPS, Intending to Break North Field Records in String Time per Well"
Authors: Vos Anton , Cross Allan , Lismont Bart , Venrooij John van , Quaden Roy 
Published: November 2008

Abstract
Historically, development wells in Qatar's North Field have taken anywhere from 70 to 100 days to drill, complete, perforate, stimulate and clean up in preparation for their long term production. To date, optimisations have predominantly focused on the Drilling and Completion (installation) scope, as a mean's of reducing the rig's critical path. Although there have been initiatives to minimize cost impacts by using cheaper alternatives to rigs for Perforation, Stimulation and Clean Up, these do not address the total critical path impact that well delivery has on Project schedules. Pearl GTL's Well Delivery initiative "SIMOPS" could potentially address some of the imbalance.
What do we mean by SIMOPS?
"Undertaking drilling and completion operations with the rig, while simultaneously performing perforate, stimulation and clean up operations on previously drilled and completed wells"
Pearl SIMOPS options included; being entirely rig based and running concurrent operations from the rig's decks, upgrading temporary wellhead decks such that the well service operations were ‘self sufficient’, and or use of a barge alongside rig / temporary decks, and numerous variants/combinations of the afore mentioned.
Initially, SIMOPS value drivers focused on; HSE, innovation, and cost savings, which were used in part for justifying a high specification jack up rig. Cost savings, based on rig days saved, were in the order of $60MM. Yet when the upfront well count increased, during the planning phase prior to FID, schedule suddenly became a very significant value driver, Well Delivery was now very much on the Project critical path.
The Value of Formation Pressure Measurements While-Drilling a Case Study from Offshore Abu Dhabi
Authors: Poirier-Coutansais Xavier , Baud Emmanuelle , Mirto Ettore 
Published: November 2008

Abstract
Formation pore pressure and near-wellbore mobility are key parameters for reservoir description. Traditionally, these data are acquired with wireline formation pressure tester. However, today a large number of wells are being drilled at high deviation, as producers and injectors, and wireline can be a time-consuming operation, as the tools must be conveyed by drillpipe. Acquiring this type of formation evaluation data with a logging while-drilling tool represents a significant time and cost savings opportunity, simultaneously improving efficiency and safety while reducing risk and non-productive time. This paper discusses the planning phase, the operational results and the lessons learned from a well drilled utilizing formation pressure testing in combination with a full logging while-drilling data suite. The formation fluid pressures, mobility and pressure gradients were taken after drilling to the well total depth during a cleanout trip. Thirty-eight successful tests were taken over several carbonate reservoirs with mobility ranging from 0.1 to 100mD/cp, achieving 100% seal success rate. A fully automated testing sequence, time optimized to 5 minutes, with variable rate, volume and number of drawdowns downhole, was used. Seal integrity and tight tests could be readily identified in real time from 6-bits per second mud-pulse telemetry. The logging while-drilling service proved it could save two days of valuable rig time by eliminating one dedicated wireline pressure-measurement run and one cleanout trip. In addition, this improvement in operational efficiency minimized wellbore exposure time, thus reducing the risks during the casing run.
Substituting Nitrogen for Hydrocarbon Gas in a Gas Cycling Project
Authors: Linderman John , Al-Jenaibi Faisal , Ghori Saleem , Putney Kevin , Lawrence John , Gallet Michel , Hohensee Kurt 
Published: November 2008

Abstract
Injecting nitrogen instead of hydrocarbon gas for pressure maintenance can be an effective means to accelerate and increase the volume of hydrocarbon gas available for sale. This paper presents results of a joint study by Abu Dhabi National Oil Company (ADNOC) and ExxonMobil that used compositional full-field reservoir simulation to evaluate the suitability of N2 injection for gas cycling in a large, Middle East gas condensate reservoir. The results of the study show that substituting nitrogen for hydrocarbon gas during gas cycling has the potential to significantly accelerate the production of hydrocarbon gas for domestic gas consumption. Although late-life condensate recovery is slightly reduced, overall hydrocarbon recovery on an oil equivalent barrel (OEB) basis is improved due to higher ultimate recovery of reservoir gas. Increasing nitrogen concentrations in the produced gas stream after nitrogen breakthrough can be managed within acceptable limits by a combination of subsurface management, nitrogen removal facilities, and/or modifications to gas-consumption equipment. Various options for generating non-hydrocarbon gas for substitution were evaluated, and it was concluded that cryogenic air separation is the most cost effective method for generating large volumes of non-hydrocarbon gas within acceptable specifications.
Using the Optimal Through-Casing Measurement to Maximize Oil Recovery: A Case Study From The Western Desert, Egypt
Authors: Van Steene M. , Herold B. , Dutta D. J. , Abugren Y. , Hosny S. , Badr A. B. , Mahgoub I. , Zidan A. 
Published: November 2008

Abstract
Accurate time-lapse saturation information is the key to making the right decisions on completion strategy, maximizing oil recovery and reducing water cut. This paper presents a case study from the Bahariya Formation, a heterogeneous fluvio-marine channel deposit in the Western Desert, Egypt.
All the wells considered in this paper showed significant water production. To identify the main water-producing zones and the bypassed oil, all the wells were logged using a through-casing formation resistivity tool. One well was also surveyed with pulsed neutron capture logs.
Based on the log results, depleted zones were identified, and the intervals contributing most to the water production were isolated. Water cut was significantly reduced. In some wells, the saturation analysis revealed that the stacked reservoir zones had variable levels of depletion and that the depletion was not necessarily related to the distance to the original oil-water contact. In these wells, the water shutoff leaves oil behind, and a different completion strategy was recommended. The results from the resistivity and nuclear measurements are discussed in detail with respect to environmental effects.
This case study demonstrates that through-casing formation resistivity measurements provide more robust answers compared to neutron measurements in the studied environment. The deeper depth of investigation is extremely valuable, as the wells cannot be logged under dynamic conditions, and fluid reinvasion is always present.
Moreover, in view of increasingly high rig rates and limited rig availability, the simple nature of the processing and interpretation of the through-casing formation resistivity log enables fast decisions.
These examples from the Western Desert illustrate how analysis behind casing provides critical information to maximize oil production and facilitate water shutoff decisions.