bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tele-Maintenance for Remote Online Diagnostic and Evaluation of Problems at Offshore Facilities, Sarawak
Authors: Mayer George , Zubir Wan Abdullah , Ming Lim Ai , Chang Robert 
Published: December 2007

Abstract
Shell Malaysia EP (SMEP) is the major gas supplier to Malaysia Liquefied Natural Plants (MLNG) namely MLNG- Satu and MLNG-Dua. Gas is piped from SMEP's five offshore Gas platforms – E11, F6, F23 (Central Luconia) – serving MLNG-Satu and M1 and M3 (M Fields) catering to the demand of MLNG-Dua. MLNG-Tiga, the third MLNG plant is scheduled to come on-stream in 2004.
With production levels reaching new heights and even tighter margins between supply and demand, it has warranted the Maintenance team to re-look at new ways to manage and secure uninterrupted gas supply to the customers.
Traditionally, whenever there was a situation which could lead to a possible gas supply interruption, frontline operation technicians on the platforms would provide the first line of "defense" in reinstating the plant and the troubleshooting process very often involved conventional telephone communication with the shore-based specialists in the head office to try and resolve the problem jointly. Failure to resolve the problem in this manner would result in the deployment of a support specialist to the affected location. An impediment faced by the support team in this arrangement is that very often it is difficult to accurately ‘visualize’ the problem and provision of the ‘correct’ advice becomes constrained. As experience has shown, some plant outages have fallen in the order of more than 24 hours and this is highly undesirable.
As it is impossible to guarantee a plant uptime of 100% indefinitely, SMEP's main stumbling block was to ensure that recovery time was kept at a bare minimal. If this can be limited to three hours or less (based on the packed pipelines pressure retention time), gas supply interruption to the customers can be avoided. Armed with the determination to seek this solution, SMEP began its journey through the threshold that marked the birth of Tele-Maintenance.
SMEP realized that to further enhance current communications between on-site technicians and shore-based specialists, a ‘visual’ perspective was vital to supplement the existing ’audio’ element via traditional telephone communication. With the innovative use of Information Technology (IT), Tele-Maintenance came into being and it was specifically designed to circumvent similar incidents. In essence, Tele-Maintenance is a tool that enables specialists to be ‘virtually’ present at these situations albeit remotely from their office. With this real-time ‘sight’, specialists are now able to collectively provide offshore support within a shorter time frame, thus eliminating the need to travel offshore (if problem can be resolved remotely), ultimately minimizing down-time.
This paper illustrates, in detail, SMEP's experience as the pioneers in the Shell Group to successfully develop and implement Tele-Maintenance for its offshore locations.
Implementation of Data Collection Automation to Support Predictive Maintenance in the Minas Field
Authors: Wulandari Nur Diani , Irawan Wawan 
Published: December 2007

Abstract
Production equipments should be maintained if it is to fulfill its function for a useful life. One of the strategies is predictive maintenance (PM) where accurate and sufficient data availability is very important. Nowadays, Human Machine Interface and microprocessor-based field instrumentation becomes a standard tool of plant stations operation in the Minas field and reduce human limitation for equipment data archival. This system combined with powerful database provides good information for PM strategies.
Improving Production Monitoring and Surveillance by Using an Integrated Production Data Management
Authors: Aprilian Salis , Maria Regina 
Published: December 2007

Abstract
Pertamina Upstream's strategy is "First Quality, Then Growth". As a part of Pertamina's drive to improve quality (productivity and efficiency), Pertamina DOH SBS which is the biggest upstream business unit of Pertamina located in South Sumatra initiated the steps, towards the end of the year 2000, to improve the overall data quality and information management process related to production monitoring and surveillance.
With the vision to fully automate the production information system, Pertamina DOH SBS reviewed the availably commercial software offered in the area of production information management. The solution is intended to provide a structured data capturing system as well as overall framework towards an integrated Production Data Management System (PDMS) for Pertamina DOH SBS.
The system implementation was successfully completed in the first quarter of 2002. It is used everyday to capture daily field production data, production allocation, and it provides "Daily Morning Production Report" posted at the Pertamina DOH SBS website (intranet) by 8am every morning.
This field data capture system replaced the MS Excel™ spreadsheet files that were used previously to capture and store daily production data. It also provides the user quality control tools like graphical visualization of historical data, which has significantly contributed towards increasing the confidence in the quality of data.
This Production Data Management System provides the engineers with reliable data, thus minimize time spend for data collecting. Instead, more time will be spent for engineering analysis to increase field productivity. Besides savings in the time, the improved quality and timely availability of data will considerably improve the success rate by allowing users to make well informed decisions.
ESP Run Life Improvement in Harsh Elastomer Environments, the Moomba Field
Authors: Young J. , Kappelhoff G. H. , Watson A. 
Published: December 2007

Abstract
Typical run lives of electric submersible pumps (ESPs) in the Cooper Basin in Australia are in the range of 600 to 900 days. ESPs have been used in 15 different reservoirs in this area. When highly productive oil reservoirs were recently discovered in the Moomba area similar run lives were expected.
However, the first 12 installations in the Moomba fields only ran an average of 87 days. In 2001 a team was formed to target improved run lives. The team included production, manufacturing, engineering and management personnel from the operating company and equipment supplier.
The main problem areas identified were protector and electrical wellhead feedthru failures and power supply quality. This paper outlines the operational, engineering and equipment changes made in each of the problem areas and the resulting increase in run lives.
Failure analysis of pulled equipment demonstrated that the elastomers utilized for motor protection were being degraded. Compatibility testing of elastomers, produced fluids and injected chemicals revealed that the produced oil and water were causing the elastomers to breakdown. Although the wells were vertical, conventional labyrinth protectors could not be used because of the low gravity of the crude. The solution was to engineer a new motor protection system that was virtually elastomer free. The design utilizes metal bellows, high-density oil for gravity separation protection and high-grade o-rings. This design resulted in the first ESP motor protection system that can be used in environments with light crude that is incompatible with standard elastomers.
In addition, analysis of the power quality showed that the crude fuel utilized to power the generator sets was affecting power quality. The poor quality of the power supplied to the ESPs was potentially contributing to motor burns and wellhead penetrator failures. To improve power quality a cleaner fuel supply was sourced.
The run life improvement project is ongoing and the outcome of increased run lives is readily demonstrated.
Comparative Evaluation of Single Vs. Multi-Mandrel Gas Lift System for an India Offshore Field
Authors: Kumar Adesh , Gupta V. P. 
Published: December 2007

Abstract
Mumbai High field is located in Western Offshore of India, 160 km South West off Mumbai City. The field was discovered in the year 1974 and put on production in May 1976. Massive development plan was undertaken in phases and a peak production rate of about 400,000 bopd was achieved during year 1984. To maintain reservoir pressure, suitable water injection scheme was put in place in 1984-85. The conventional multi-mandrel gas lift system was applied as artificial lift mode and operating in the field since 1987.
In multi-mandrel conventional gas lift system, 4-6 mandrels are used in the well. The GLVs in upper mandrels work as unloading valves and orifice valve in last mandrel act as operating valve. As mentioned earlier, the gas lift started in the year 1987 in this field and in 1994-95, a significant number of wells (more than 100 wells) were put on gas lift. The system utilizes compressed gas at 1000 to 1350 psi (at well head) in different complexes. The existing compression system is an integrated system, which supplies gas to gas-lift network and balance gas to sales line leading to onshore plant. Presently, 381 wells are operating on gas lift (out of 454 wells completed with gas lift) and contributing about 80% of total oil production from Mumbai High.
During the incipient stages of gas lift, CFP recommended single mandrel single point gas lift system with a gas lift pressure of 1800 psi for unloading and 1400 psi for normal gas lift operation. Considering the availability of present gas compression system at about 1400 psig, as per worldwide practice, conventional gas lift system with multi-mandrels in place was accepted by ONGC. By doing so, major compression system revamp and consequent delays were avoided.
In the recent past, some of the major operators, especially in North Sea, have applied the Single Mandrel Gas Lift System (referred here as Single Point Gas Lift) to overcome the inherent disadvantages of conventional gas lift system. Presently, Mumbai High is undergoing major additional re-development plan to augment oil production, the present conventional gas lift system needed re-look to draw a learning curve. It is in this context, a detailed exercise has been carried out to evaluate the present conventional gas lift system involving its efficacy and well servicing costs.
The present paper analyzes advantages of single point gas lift over conventional gas lift, the requirements of single point gas lift for Mumbai High, efficacy of conventional gas lift system, present major and minor well servicing costs and other related issues for implementation in Mumbai High. A detailed techno-economic analysis is presented. It is observed that the multi-mandrel system of gas lift is more effective for this field and should be pursued for future development schemes of this field.
The field is currently undergoing a major redevelopment exercise. Hence, a cost-economic evaluation of present system is essential for future decision process.
Experimental Design in Deterministic Modelling: Assessing Significant Uncertainties
Authors: Peng Cheong Yaw , Gupta Ritu 
Published: December 2007

AbstractThis study investigates the feasibility of using experimental design and analysis methods within the 3D geological modelling framework, which includes the discussions and guidelines of: (1) how to select appropriate designs; (2) how to determine the number of experimental runs; and, (3) how the experimental response can be modelled accurately with the statistical modelling methods to develop a surrogate equation model. This methodology can systematically and significantly reduce the number of models that must be generated to cover the effects due to all the input uncertainties in multiple deterministic modelling. The approach is valuable in assessing the various sources of uncertainty in 3D geological modelling, and to study how they affect the hydrocarbon in-place volume. In brief, the approach uses expert knowledge and a decision tree to consider the input variables and the full range of possible geological models. Then, experimental design methods and expert opinion are used to select a subset of models that must be built to cover the whole uncertainty range. A response surface equation model is fitted to develop a surrogate equation model, which represents the ‘actual’ modelling experiment. This can provide a valuable insight into the behaviour of the input uncertainties, and the output response distribution. Finally, this surrogate equation model must be evaluated to justify the results.The above approach is demonstrated using: (1) a simple multiplicative hydrocarbon in-place volume equation, (2) an Excel spreadsheet built to mimic the 3D geological modelling workflow to provide some guidelines on the possible effects (interaction, nonlinear) and design selection; (3) 3D geological modelling (multiple deterministic) to assess the input variables of a fluvial reservoir. A few key variables were found to be significantly affecting the hydrocarbon in-place volume. The designs used were Placket-Burman, 2k-p and 3k-p fractional factorial designs, either with or without some modifications. These selected designs were ranging from 9 to 27 runs/models.In conclusion, a simple two-level fractional factorial design, such as Placket-Burman, is sufficient to assess and rank the input uncertainties in 3D geological modelling, as only the main linear effects are dominant. This permits future data acquisition to be optimised to reduce uncertainty. On the other hand, where the aim is to predict hydrocarbon in-place volume, nonlinear and interaction effects are significant, and a more sophisticated design, such as a modified two-level fractional factorial design with central and axial points, is required. The surrogate equation model can be used to determine the in-place volume distribution and to extract the possible P5, P50 and P95 models.
A Computer Aided System of Geology-Engineering-Economy-Production Synergy for Optimization of Integrated Reservoir Management
Authors: Du Zhimin , Liang Baosheng , Xie Dan , Chen Xiaofan 
Published: December 2007

Abstract
Reservoir management widely accepted as a concept has been paid close attention in Chinese petroleum industry. However, there are innumerable barriers in operation mainly because of the lack of powerful platform to effectively support multidisciplinary cooperation. As a result, after a period of fast development, the geology-engineering-economy synergy arrives to a plateau and becomes a mirage suitable only in theory, which in turn reduce the confidence in the viability of optimum reservoir management.
This paper provides a systematic approach to integrated reservoir management by a computer aided system, based on a database of China National Petroleum Corporation. The system includes seven organic sub-systems: geology information integration, development information integration, reservoir engineering calculation, production performance analysis, economic evaluation, real-time monitoring, data management and maintenance. The function of each part and tightly mutual collaboration are presented. More specifically, through the access to the database in which data of different specialized areas are originally separate, all the information since reservoir exploration is shared orderly on the platform of this computer aided system. Graphs, curves, spreadsheets and other engineering and economic analyses can be generated automatically with any selected area or well groups. Teamwork is realized conveniently, and the dynamic-static performance combination is obtained through comfortable communications among geologists, field engineers and economists on the computer aided reservoir management system. Furthermore, because the routine production management is optimized through real-time monitoring, especially its visualized performance analysis, it is a handy assistant for high-level managers to know how the operation process works, to make reasonable decision and to adjust the strategy timely. In this way, geology, engineering, production and economy are integrated expediently and the traditional bottleneck is solved. Additionally, the successful applications of reservoir management system designed in this paper are briefly introduced in some oil fields such as Dagang Oil Field and Zhongyuan Oil Field in China.
The Effect of Fracture Characteristics on Reduction of Permeability by Asphaltene Precipitation in Carbonate Formation
Authors: Zekri Abdulrazag Y. , Shedid Shedid Ali 
Published: December 2007

Abstract
Crude oils produced in many parts of the world contain asphaltene. Asphaltene plugging is a known cause of near-wellbore formation damage. The deposition phenomenon of asphaltene has been extensively investigated in homogenous porous media. However, we have not found any reported experimental work on asphaltene plugging in naturally or artificially fractured reservoirs. The main objective of this study is to investigate the effect of fracture characteristics on reduction of permeability by asphaltene deposition in carbonate formation.
A single fracture system is made with different fractures characteristics such as porosity, permeability, and fracture angel using saw-cut limestone core samples with metallic plate. The fracture aperture was kept constant for most of the studied systems. The effect of flow rate, fracture angel, matrix to fracture permeability, asphaltene concentration and the state of stress on the retained permeability is presented. Different fracture angle orientations of 45°, 90°, and 180° relevant to the axis of the flow were investigated. A non-invasive imaging technique-Scanning Electron Microscopy (SEM) was employed to visualize changes on the surface of the fracture as a result of aspheltenic crude oil flow through the system.
Reducing Evaluation Cycle-Time in Complex Reservoir Settings: A Case Study from South West Ampa Field, Brunei
Authors: Holyoak S. C. , Hayon S. 
Published: December 2007

Abstract
The content of this paper is based on the ongoing evaluation of the South West Ampa Field, Brunei, and encompasses the processes executed from seismic interpretation through to structural and reservoir modeling. South West Ampa is a large, complex oil and gas field, with more than 100 stacked, highly compartmentalized reservoir intervals. Original fluid contacts are typically not common between adjacent fault blocks. In this challenging setting, the approach used in the past to evaluate reservoir fluid distribution and volumetrics relied heavily on conventional mapping packages and intensive draughting efforts. The constraints imposed by software and processes resulted in cycle-times of several years. Recently however, Brunei Shell Petroleum (BSP) has conceived innovative solutions to manage the inherent complexity, and significantly reduce evaluation cycle-time. The workflow described maximizes use of legacy data, and culminates in a tightly integrated full-field 3D model. A new approach to utilizing corporate fluid contact data has resulted in breakthrough performance in the area of fluid distribution modeling and volumetric calculations. The majority of the processes covered in this paper are also applicable to less complex settings. At South West Ampa Field, the cycle-time of the evaluation process has been significantly reduced.Working in a highly integrated 3D environment facilitates quality control of the model.The model and the resultant maps / cross-sections are based directly on corporate data. Any inconsistencies are highlighted, and can be corrected at source. The model and its derivatives can be rapidly updated with new or re-evaluated data.
The paper is fully supported by examples from the South West Ampa Field.
Extracting Capillary Pressure and Global Mobility from Spontaneous Imbibition Data in Oil-Water-Rock Systems
Authors: Li Kewen , Horne Roland N. 
Published: December 2007

AbstractAn approach was developed to extract the imbibition capillary pressure and the global mobility data from spontaneous water imbibition tests in oil-water-rock systems. Capillary pressure and global mobility data were calculated using this method with the experimental data of countercurrent spontaneous water imbibition tests in different rocks and at different interfacial tensions. The calculated capillary pressures were consistent with the change in interfacial tension. The oil-water-rock systems with greater interfacial tensions had greater capillary pressures. However the oil-water-rock systems with greater capillary pressure may not have greater imbibition rate. The calculated values of the global mobility and the imbibition index explain why the oil recovery or the imbibition rate in systems with high interfacial tension was smaller than that in systems with low interfacial tension, which has been considered a paradoxical result for many years.
Internal Environmental Corrections for a New Carbon Oxygen Logging System
Authors: Jacobson Larry A. , Truax Jerome , Durbin Dennis P. 
Published: December 2007

Abstract
Modern Pulsed-Neutron Spectrometry (PNS) well logging tools produce measurements (e.g., Carbon/Oxygen (C/O) ratio, lithology (Ca/Si) ratio, elemental yields, etc) that are impacted by internal as well as external factors. The external ones are well known: porosity, lithology, borehole size, casing size, cement thickness, borehole fluid type, centering, tubing size, to name a few. These factors have been discussed extensively in the literature and will not be addressed here.
Internal effects have not, however, been extensively discussed in the literature. They arise from unit-to-unit variations in component characteristics. Some examples are scintillator and photomultiplier performance, dead-time and pulse pileup effects, electronic, and analog-to-digital converter linearity. All of these will be discussed here. These internal effects generally lead to differences, from unit-to-unit, in the absolute magnitude of output quantities measured (C/O ratio, lithology ratio, for example). Fortunately, the log character (i.e. the variations with depth) is usually preserved. Unit-to-unit variability is of concern in well monitoring projects because of the likelihood that logs will be obtained with different tools (perhaps even different vendors) over the lifetime of a well.
These internal effects are examined using a database of measurements made in the same zone of a single test well. The database was generated from several dozen tools; each calibrated in the same fixture. Using this database, corrective schemes were devised that minimize internal effects, thereby producing measurements that are more consistent from unit to unit. The corrective schemes are parameterized in the calibration process for each tool and applied to all log data run with that particular tool.