bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bayesian modelling of compositional heterogeneity in molecular phylogenetics
Authors: Heaps Sarah E. , Nye Tom M.W. , Boys Richard J. , Williams Tom A. , Embley T. Martin 
Published: August 2014

AbstractIn molecular phylogenetics, standard models of sequence evolution generally assume that sequence composition remains constant over evolutionary time. However, this assumption is violated in many datasets which show substantial heterogeneity in sequence composition across taxa. We propose a model which allows compositional heterogeneity across branches, and formulate the model in a Bayesian framework. Specifically, the root and each branch of the tree is associated with its own composition vector whilst a global matrix of exchangeability parameters applies everywhere on the tree. We encourage borrowing of strength between branches by developing two possible priors for the composition vectors: one in which information can be exchanged equally amongst all branches of the tree and another in which more information is exchanged between neighbouring branches than between distant branches. We also propose a Markov chain Monte Carlo (MCMC) algorithm for posterior inference which uses data augmentation of substitutional histories to yield a simple complete data likelihood function that factorises over branches and allows Gibbs updates for most parameters. Standard phylogenetic models are not informative about the root position. Therefore a significant advantage of the proposed model is that it allows inference about rooted trees. The position of the root is fundamental to the biological interpretation of trees, both for polarising trait evolution and for establishing the order of divergence among lineages. Furthermore, unlike some other related models from the literature, inference in the model we propose can be carried out through a simple MCMC scheme which does not require problematic dimension-changing moves. We investigate the performance of the model and priors in analyses of two alignments for which there is strong biological opinion about the tree topology and root position.
Origin of Galactose‐Deficient Immunoglobulin G in Gingival Crevicular Fluid in Periodontitis
Authors: Komiyama Yuske , Kafkova Leona Raskova , Barasch Andrei , Shah Ging R. , Grbic John T. , Novak Zdenek , Komiyama Kazuo , Novak Jan , Mestecky Jiri , Moldoveanu Zina 
Published: August 2014

Background: Periodontitis is a chronic inflammatory disease initiated by a synergistic and dysbiotic microbial community that elicits a gingival inflammatory response leading to tissue breakdown. Periodontitis shares many characteristics with other chronic inflammatory diseases, including abnormal glycosylation of immunoglobulin (Ig)G. The current authors have previously demonstrated that IgG from gingival crevicular fluid (GCF) of patients with chronic periodontitis contains galactose (Gal)‐deficient IgG.Methods: The origin of the aberrantly glycosylated IgG was determined by measuring levels of Gal‐deficient IgG in GCF and serum from patients with periodontitis and non‐periodontitis controls using lectin enzyme‐linked immunosorbent assay. The Ig‐producing cells and the proportion of cells producing Gal‐deficient IgG were immunohistochemically determined in gingival tissues from patients with periodontitis by fluorescence microscopy. The results were statistically evaluated and correlated with clinical data.Results: The results indicate that GCF of patients with periodontitis had higher levels of Gal‐deficient IgG compared with controls (P = 0.002). In gingival tissues, IgG was the dominant isotype among Ig‐producing cells, and 60% of IgG‐positive cells produced Gal‐deficient IgG. Moreover, the proportion of Gal‐deficient IgG‐producing cells directly correlated with clinical parameters of probing depth and clinical attachment loss (AL).Conclusion: These results suggest that the presence of Gal‐deficient IgG is associated with gingival inflammation and may play a role in the worsening of clinical parameters of periodontitis, such as AL.
A Quasi Intelligent Flow Control Device for Water Injectors
Authors: Bowen Eddie G. , Aadnoy B. S. 
Published: August 2014

Abstract
According to industry wide surveys, the number of wells drilled as injectors relative to producers are on the rise. The cause being driven by the knowledge gained from industry's experience and need to maintain pressure support during the entire production life cycle of a well improving ultimate oil recovery.
One of the biggest challenges with water injectors is how to manage an efficient sweep of the oil. An early breakthrough event when attempting to manage pressure maintenance is undesirable because it leads to unwanted water breakthrough in the producing well and leaves behind valuable oil reserves. This ultimately increases the cost of production and reduces net revenues on a per well basis.
This paper introduces an innovative, cost-effective solution resulting in an efficient sweep of the producing zones and improved oil recovery. Sustaining control of where the water is distributed in vertical cased hole wells versus long open hole lateral sections requires some type of down hole mechanical mechanism directing the injected waters to the desired zones of interest. One way to accomplish this is through an expensive intelligent completion where feed through capabilities are required for production packers and wellheads. Another is to install a passive inflow control device that passively controls the outflow of water via the use of an orifice or some type of unique geometrical shape that is dependent on a pressure drop, providing the distribution along the intervals length. A third method is providing as much flow area as possible in the lower completion and allowing the water to go where it wants to go.
Laboratory testing and modeled simulated results for the quasi-intelligent flow control device will be presented in a manner that compares the different methods available along with hardware requirements to achieve an effective quasi-intelligent completion for water injectors.
Highest Reliability Provides World Class Benchmark for Permanent Downhole Monitoring Installation and Data Delivery in Malaysia
Authors: Samuel Orient B. , Khalid M. Zaidan , Raw Ian , Singh Premjit Kaur 
Published: August 2014

Abstract
Reservoir pressure and temperature measurements have become the cornerstone of reservoir and production management. These measurements provide improved capabilities for understanding of oil and gas reservoir characteristics, which enables greater reservoir management for increased production and improved ultimate recovery.
The reliability and accuracy of permanent downhole pressure and temperature technologies is therefore of the highest priority when planning field developments, be it green fields, brown fields, marginal fields or EOR projects. A long term Permanent Downhole Gauge and Fiber Optic monitoring contract was awarded in August 2010 with the intent to provide reservoir monitoring with the highest reliability and accuracy that was available. Since the award of the contract, the world-class milestone of 50 installations was achieved in August 2013. This milestone was enhanced by the fact that, an amazing success rate of 100% was realized.
As of June 2014, the number of installations has increased to more than 80 gauges while maintaining the 100% success. This has provided increased confidence for the operator to expand deployment of permanent downhole gauges to higher pressure and temperature environment.
This success story has been achieved by a combination of many factors, from the strong validation process for gauge selection and subsequent choice of world class technologies with the highest survivability in the oil industry, close collaboration between the project and operations teams of the oil company and service provider, project management expertise, detailed preparation and maintenance, to the philosophy of providing real time data delivery to the end user.
This paper provides an update of the remarkable success story including the technologies installed, the progression into increasingly higher pressure and temperature environments, and examples of the benefits observed from the access to reliable and accurate downhole pressure and temperature information.
Novel Integrated Hole-Cleaning Concept Reduces Well Construction By 3 Rig Days
Authors: Heitmann Norbert , Chacinet Euro , Molero Rafael , Graterol Willy , Ouali Yazid , Burgos Elias Chamat , Cisneros Agustin 
Published: August 2014

Abstract
A new hole-cleaning process applied in a PDVSA Servicios Drilling Project, in the Heavy Oil Orinoco Belt, Bolivarian Republik of Venezuela saved 3 rig days and reduced the stuck-pipe risk and avoided damage to the MWD/LWD BHA and PDC bit. A long sought solution for effective wellbore cleaning was validated. Applied the first time, this concept provides a novel integrated solution for hole-cleaning, is transferrable to other well construction projects, is reducing project costs, lessens lost-in-hole BHAs and significantly reduces flat drilling time & invisible lost time.
Effective hole-cleaning is the main challenge of any deviated drilling operation, with problems in cuttings and cuttings beds removal. Even optimized mud flow rates, with reciprocal and rotational pipe movements physically cannot completely remove cutting beds. The herewith presented solution constitutes to incorporate a non-rotational scraper assembly into the drill string, applied together with an engineered and optimized hole-cleaning process.
With no access to dedicated casing cleaning tools, the 9 5/8” casing was cleaned from cuttings by back-reaming inside the casing with the BHA drill string, requiring minimum 2-3 runs and 2 days, and causing excessive wear on casing, BHA and PDC bit. After drilling the 8 ½” section, the new concept was to place a non-rotational scraper assembly into the drill string, allowing only minimum POOH of DP stands as part of the scheduled final openhole wiper trip activity, followed by RIH back to TD – and as such completing the openhole wiper trip without the need of tripping the drill string to surface. The tested solution eliminated all back-reaming inside casing and ensured a full 360° casing contact cleaning prior to RIH the liner, guaranteeing the casing is free of cuttings and also eliminating any additional round nose mill trips. The scraper never moved outside the 9 5/8” casing. This first application of RIH a scraper as part of the drill string gave outstanding results with 3 rig days been saved and a smooth RIH of the liner.
Using E-Line to Restore Well Injection on a Limited Space Platform - A Case Story from India
Authors: Nayak Jyoti Prakash , Parasher Arunabh , Anand Saurabh , Sharma Anurag , Pinto Thomas 
Published: August 2014

Abstract
Crane, space and height restrictions often pose problems when it comes to traditional intervention methods; adding daylight requirements, which are often a result of such platform restrictions, makes interventions even more challenging.
When slickline jarring failed to remove a lock mandrel despite more than 300 attempts, an operator on a platform, offshore India's East Coast, turned to an alternative solution on electric line (e-line). The well was being converted into an injector to facilitate pressure support for producing wells in a marginal field, but injection was not possible due to a choked ‘thru tubing sand screen’ (TTSS), placed through a 3.5 in. lock mandrel set on a 3.5 in. sliding sleeve door (SSD) nipple.
Thorough risk assessment and testing was conducted onshore to prepare for this region's first operation; however, the first run revealed that the GS profile couldn't latch on to the lock mandrel due to debris settled on top of the TTSS. A readily available clean-out solution was quickly mobilized and arrived within 12 hours. This clean-out tool incorporated a high volume suction technology and bailer sections to remove debris. Around half a liter of debris was removed allowing the subsequent run with an electric-over-hydraulic stroking ram to retrieve the lock mandrel without further complications.
Using e-line with the right blend of technology provided cost-effective management for the project and thus avoided a barge-based coiled tubing (CT) or workover rig operation involving much higher risks and costs. Post retrieving the TTSS, the well was put on injection successfully with around 22,000 barrels of water per day (BWPD) injection rate against zero injectivity prior to the operation.
This paper will report the first ever attempt of releasing a lock mandrel using e-line in the Asia Pacific region. It will review the job planning, project management, trouble shooting and execution, as well as report the lessons learned to derive best practice considerations for future operations.
First Non-Retrievable Casing Drilling Technique with Automated Surface Drive System to Improve Top Hole Drilling Performance - Vietnam Offshore
Authors: Chuong Hwong Yew , I Made Budi Utama , Wang Keith Won 
Published: August 2014

Abstract
Casing while Drilling (CwD) technology has become a favorable drilling technique and gaining attention among operators across the Asia Pacific region due to its field proven reduction in drilling flat time and as a solution to potential downhole problems. The non-retrievable CwD technique includes a drillable casing bit and float collar assembly attached to the lower end of the casing string. The entire casing string is driven by a surface drive system. Cementing can be carried out immediately upon reaching total depth. A conventional drilling assembly is subsequently deployed to drill out the casing bit and next hole section, without the requirement of a special drill-out trip.
Previous successful CwD operations for top hole sections of offset wells in Malay–Tho Chu Basin offshore Vietnam, have encouraged the operator to further improve the drilling efficiency. The operator planned to install 13-3/8″ conductor casing utilizing CwD techniques in similar lithologies with an even more efficient, safer, and automated surface drive system. An automated surface drive system was selected to replace the conventional manually operated casing drilling spear which was used in the previous campaigns.
The automated surface drive system combines conventional casing running equipment into a single unit, allowing string rotation and push-down while running, circulating, or reciprocating. The system's integrated measuring shaft gives more precise torque readings when making up a connection.
This paper discussed the first case history of successful planning and implementation of CwD with the automated surface drive system in Vietnam. Emphasis is placed on the entire process from the pre-job engineering planning stage until project execution, as well as the improved drilling performance and outcomes.
Successful Strategy to Minimise Non-Productive Time for Drilling Deepwater Well with Newbuild 6th Generation Drillship
Authors: Prasertamporn Praisont , Rattanachan Sarit , Maheshwari Mukesh 
Published: August 2014

Abstract
The first PTTEPI deepwater well in 1,003m water was drilled in the Gulf of Martaban, Myanmar in 2013. The tight deepwater rig market and single well program made it difficult to secure a rig, but a newbuild 6th generation drillship was eventually contracted. Non-Productive Time (NPT) is always the major concern when using a newbuild, especially in deepwater where the operational cost was 62,500 USD/hour. This paper explains how NPT was kept to acceptable level, describing the procedures employed.
The drillship used was identical to a sister rig which had already started the operations and lessons were learned from that. Start-up NPT from the previous rig was found to be 12.4% in the first 2 wells and the majority of this resulted from drawworks, BOP and Top-drive issues. Sub-sea equipment downtime was especially damaging in deepwater due to the extended time required to pull and re-run the BOP. This area was, therefore, a primary focus.
Third party inspection of BOP systems was witnessed by company representatives and a comprehensive testing and inspection program was designed to simulate operations wherever possible. Pre-running and Post-running tests were performed per API standard 53 and all tests were completed successfully. When the rig was in operation, BOP running procedures were strictly enforced. Contractual clauses were also agreed between the contractor and operator to minimise the impact of any start-up NPT.
Logistics planning of equipment, bulk, and chemical also played important part of downtime minimization. As the turnaround time from shorebase to well location was 5 days, lots of loadings had been done before rig departed from Singapore.
At the end of the well, drilling operations were found to have been performed efficiently. Rig NPT was only 6.9%, but with the majority of this resulting from problems with a new design of diverter system. This level of NPT was impressive for a newbuild high technology drillship, being 70% lower than the figure for start-up of the sister unit.
Challenges of Casing Design in Geothermal Wells
Authors: Torres Angelito 
Published: August 2014

Abstract
Casing and tubing in either oil and gas or geothermal wells are designed to withstand pressure loads (burst and collapse) and axial tension - the typical parameters that should be considered in any casing design. However, in geothermal applications, temperature is a major consideration in casing design because of thermal stresses generated by the high temperature geothermal fluids. Elevated temperature reduces the yield strength of the casing which essentially reduces the burst rating, collapse resistance and tensile strength of the material.
High temperature will be experienced by the well once it is on production. The cemented casing strings will be subjected to significant cyclical axial stress caused by changes in temperature due to production of high temperature geothermal fluids that can then be followed by the injection of cold water for well kill operations to perform wellbore maintenance. During production, the cemented casing will enter a compressive state where plastic deformation occurs since the casing is not allowed to expand. When cold water is injected to kill the well, axial tensile stresses are generated. This paper will explore this thermally induced cyclical loading in geothermal wells, and discuss how to account for these loads in the design process.
Another consideration in casing design is the selection of threaded connections that can maintain strength and seals at elevated temperatures. It is also important to evaluate the potential of trapping water in the annulus between two casing strings during cementing operations. When the well is put on production the water expands due to the large increase in temperature, creating a significant amount of pressure between the two casing strings, which can lead to a collapse failure of the inner string or a burst failure of the outer string. Examples of these failure mechanisms will be discussed in detail.
Successful Utilisation of Conventional Cement System to Mitigate Shallow Water Flow Risk in Deepwater Block M11, Myanmar
Authors: Prasertamporn Praisont , Maheshwari Mukesh , Olutimehin Kunle , Vargas Bermea Jorge Andres 
Published: August 2014

Abstract
In 2013, PTTEP drilled a deepwater well in the Gulf of Martaban, Myanmar. The water depth was 1003m with riserless drilling over 1000m below seabed. Being exploration well without any reliable offset well, shallow hazards risk was high. Shallow hazards analysis was performed, showing the high risk of shallow water flow. Shallow water flow causes many incidents, including surface casing cement failure. It can happen during cementing, cement phase transitioning, and after the cement has set. Cementing with the shallow water flow presence is, therefore, the critical operation to achieve the well integrity. Using special cement systems, foam or ultra-lightweight, is expensive, logistically challenging, and operationally complicated. After thorough risk analysis and mitigation, conventional class G cement system was selected.
Information from 12-1/4″ pilot hole and actual 26″ hole were analysed for cementing plan. Shallow water flow occurred at 1819m in pilot hole. Pump and dump was started from 1760m in 26″ hole to prevent the flow. However, drilling to 2005m encountered another strong flow. So, the critical zone was identified from 2005m downward. For operational success, the critical zone was covered by gas tight tail slurry with API fluid loss control less than 50 mL/30 min, a SGSA transition timer shorter than 30 minutes and a short thickening time to prevent formation fluid migration. Lead slurry was designed for sufficient density and long thickening time to provide enough hydrostatic pressure, preventing fluid migration while tail slurry was setting. Not being ultra-lightweight cement, slurries were pumped with high excess and contain fibrous LCM to mitigate losses risk. Centralisation also contributed to the cementing success.
During the cement job, good returns had been observed. No shallow water flow occurred during and after cementing. Operation was continued without subsidence issue.
This paper summarises the process of assessing the risks and designing the economical cement operation to mitigate the risks, resulting in safe operation from shallow hazards.
Tackling Drilling Challenges Through Engineered BHA and Optimized Drilling Parameters: A Case Study from the Niger Delta
Authors: Okoronkwo Anayo , Ibrahim Timothy 
Published: August 2014

Abstract
In the Niger Delta in Nigeria, some fields are classified as tough drilling environment due to numerous challenges encountered during the drilling phase of well construction process. In the Gbaran field in the Niger Delta, the greatest challenge is encountered in top hole drilling in 16” hole size and above. From a stratigraphical standpoint, the surface hole formation down to 6000ft in this field and other fields of similar drilling challenges shared common characteristics, with the lithology ranging from soft and loose to medium and abrasive sand inter-bedded with stringers of lignites, gumbo shale, and hard streaks (cemented sand). Bottom hole assembly (BHA) failures such as wash outs, cracks and twist-offs caused by erratic torques, excessive lateral, axial and torsional vibration are regular occurrence while drilling top hole at depths between 3000ft and 6000ft. From offset well records, more than 75% of 16” and 17-1/2” surface hole drilled in the Gbaran field ended up with unplanned side-tracks due to twist-off and lost hole. In some wells, the non productive time arising from these failures is up to 100% of planned AFE time for the section with the attendant cost impact on the wells in addition to lost-in-hole charges.
To address these challenges, steps were taken to analyse the failures in the offset wells and come up with BHA design capable of withstanding the inherent down-hole vibrations and shock. This paper discusses this engineered approach which is centred on two things: Fit-for-purpose BHA design and optimized drilling parameters. It also highlights the success story of drilling the deepest 16” hole so far in the fields without BHA failure as experienced in other wells drilled in the same field. The result from field application showed a tremendous reduction in drilling days from average of 27days per well in the last three offset wells to average of 9.5 days per well. Furthermore, the MWD output of down-hole vibration chart also showed a 50% reduction in severity compared to offset wells in the field.