bluuebunny/crossref_metadata_2025_split huggingface dataset:
Natural Gas: The Green Fuel of the Future
Authors: Taylor R. S. , Tertzakian P. , Wall T. , Wilkinson J. , Graham M. , Young P. J. , Harbinson S. W. 
Published: February 2011

Abstract
As populations and economies continue to grow globally, energy demand will grow proportionally. Extensive work by Peter Tertzakian (2006, 2009) has shown crude oil supplies may not keep pace with this increased demand. The shortfall must be met by other energy sources.
Only two current energy sources have the global capacity to, by themselves, address increased energy demand in a timely manner. These are natural gas and coal.
Traditionally, the major use of crude oil has been for processing into transportation fuels, with lesser amounts being used for petro-chemicals and home heating. Natural gas and coal have been used primarily for electrical generation and heating.
A pivotal transition will likely occur in which natural gas and coal begin to see increased use as transportation fuels. A battle for market share between primary fuels will likely ensue.
The objective of this paper is to present data comparing the environmental impact of using methane vs. coal. A compelling case for the use of natural gas as the future "green fuel" emerges.
Safety Valve for Ultradeepwater Applications
Authors: Sloan Jim , Darren Bane 
Published: February 2011

Abstract
In recent years, offshore oil and gas exploration has continued to push into deeper and deeper waters, such as those in the Lower Tertiary fields of the Gulf of Mexico. As these field discoveries are being completed, the application requirements for safety valve installations are moving toward valves that can be set very deep, but still only require a relatively low operating pressure to control the valve. In traditional safety valve applications, operating pressures are sensitive to the wellbore pressure and are typically above those pressures to hold the valve in the open position. As the setting depth of these valves goes deeper, the operating pressures increase to a significant level such that umbilical and wellhead design and performance is detrimentally affected.
As a result of these constraints that occur in deep, offshore fields, a safety valve solution is desired to provide an ability to minimize opening pressures by balancing tubing pressure in high-pressure/high-temperature (HP/HT) conditions, yet allow extreme valve setting depth capability without compromising operational characteristics such as high opening pressures or pressure-balanced pistons using long-term valve gas charge storage.
This paper discusses a new surface-controlled, subsurface safety valve (SCSSV) that uses the low opening pressures of a tubing-pressure-insensitive safety valve, without gas-charged assisted closure or dual control lines for balanced line applications. This system enhances valve reliability by eliminating the need for pressure reversals across the valve’s critical actuating piston seals while maintaining tubing pressure insensitivity. This system provides for much deeper valve depth capabilities compared to the methods previously discussed and also allows the safety valve to account for annulus pressure buildup scenarios not possible in current SCSSV applications.
This paper presents design and development considerations for a new SCSSV solution allowing ultradeep setting depths without closed volume gas charged spring techniques utilized in current deep-set SCSSV technology. Test results will demonstrate the features, benefits, and reliability of this new safety valve in reference to previously unattainable valve operating depths in aggressive subsea well designs or annulus pressure buildup scenarios.
An Overview of Horizontal Well Completions in the Haynesville Shale
Authors: Thompson J. W. , Fan L. , Grant D. , Martin R. B. , Kanneganti K. T. , Lindsay G. J. 
Published: February 2011

Abstract
A steep learning curve has evolved in drilling and completing horizontal wells in the Haynesville shale. The challenge is to understand the production mechanism of the Haynesville and how completion practices in relation to lateral lengths, stages, and stimulation treatments relate with production.
This paper gives an overview of the Haynesville horizontal well production, the dominant factors which effect production, and a detailed analysis of the completions. Dominant factors which effect production in the Haynesville shale can be broken into four categories: geology/petrophysics/geomechanics, landing and placement of the lateral, completions, and production control. Integrating all four categories together is critical to characterize well performance and optimize future production; however, this paper focuses primarily on the completions.
Self-organizing maps (SOMs) of 49 wells in the Strait area of the Haynesville shale reveal that high producing wells have been treated primarily with slickwater, high fluid and proppant volumes, moderate amounts of 100-mesh sand, and moderate pump rates per perforation. These wells are typically located in cluster spacing of about 75 ft and have stage lengths of about 300 ft. Most show lower post-fracture instantaneous shut-in pressure (ISIP) than lower-producing wells. These observations and characteristics of high producing wells along with best completion practices can help design optimal completions and stimulation treatments in the Haynesville.
Latest Technological Advances in Rod Pumping Allow Achieving Efficiencies Higher than with ESP Systems
Authors: Takacs Gabor , Belhaj Hadi 
Published: February 2011

Abstract
Two of the most important artificial lift methods applied in oil wells are sucker-rod pumping and electrical submersible pumping with thousands of installations all over the world. Their operational features and application ranges are quite different but in many cases any of them can be used in a given well. The final selection of the proper method has to be based on their energy efficiency and the one requiring the least amount of surface power input is selected. This paper provides the necessary background for evaluating the effectiveness of the two lift methods investigated and for pinpointing the requirements of achieving maximum power efficiency of artificial lifting.
The power flow in the pumping system is investigated and the sources of power losses along with their usual ranges are described. The overall power efficiency of the system is defined by a simple formula that provides the necessary insight into the main components of the power losses occurring in different system elements. A thorough investigation of the efficiency components allows one to find the factors that most markedly influence the total system’s power requirement. As shown in the paper, the most important requisite of achieving maximum effectiveness is the proper choice of the pumping mode, i.e. the combination of plunger size, stroke length, and pumping speed.
The calculation of energy losses in the components of the ESP system is detailed and the relative importance of the individual losses is shown. Since the components of the ESP system are connected in series, a relatively simple formula can be used to describe the effect of electrical and hydraulic losses on the efficiency of the total system. The terms of the final formula were investigated for their importance and for their contribution to the overall effectiveness of the ESP system. Results of this investigation provide crucial information on how to design an ESP system to provide the highest power efficiency.
The practical use of the proposed calculation models is illustrated by presenting an example case where a relatively high liquid rate (1,300 bpd) from the same well is produced by rod pumping and ESP. Detailed installation designs resulted in several different operation modes for both sucker-rod pumping and ESP. The paper proves that using the latest technologies like high-strength sucker-rod connections, sucker-rod pumping can successfully compete with ESP installations by attaining higher energy efficiencies.
Carbon Sequestration From Waste via Conversion to Charcoal: Equipment for a Small Scale Operation
Authors: Gupta S. C. , Struyk A. , Gilbert D. 
Published: February 2011

Abstract
Carbon emitted on account of our continued use of fossil fuel can be offset using carbon capture and storage (CCS). The technology for this exists, however the economics of it is context dependent and CCS is shown not to be very cost effective in oilsands. Committing to the needed large scale sequestration projects without properly considering alternatives can prove costly at both economic and social levels. Charcoal sequestration, discussed earlier by Gupta carries with it a few advantages such as being less costly and lacking any post operation liabilities. Above all, it is reversible allowing flexibility of policy and operation and avoiding long term or large scale commitments.
The economics of the charcoal approach depends mainly on two factors: the cost of the feed biomass and the cost of processing. The first of these is addressed by using municipal waste as feedstock which can be available free of charge. Expectedly the cost of processing, the second factor, depends on the apparatus and the scale of operation.
In this paper, the authors discuss prominent traditional and modern apparatus used for conversion of biomass to charcoal with their benefits and drawbacks and describe a simple and pragmatic apparatus which could be assembled relatively easily, for a small scale operation such as processing industrial camp generated solid organic waste.
Offsetting carbon in this manner can obviously be a good way to initiate demo projects for the charcoal sequestration approach as it also helps with waste management. These demo projects in turn will help evaluate various aspects of this novel method of sequestration, and enhance public awareness on the subject which in turn will help the larger society make an informed choice to embark on a right course of action for atmospheric carbon abatement. Additionally, in light of the growing per capita waste worldwide, use of municipal waste as feedstock for charcoal sequestration can be a significant measure of carbon offset at global scale in its own right.
Proactive Maintenance Plans for RTUs of Transmission Pipelines
Authors: Tarabzouni Thamer , Al-Harbi Lafi , Al-Mejna Abdulaziz , Puthukattu Nazir 
Published: February 2011

Abstract
Remote Terminal Units (RTU)s are field devices that are used to remotely control various assets like valves during normal operations and emergency situations. RTUs obtain real-time operational data for field assets and send them to designated SCADA systems. The status of RTU communication links must be monitored closely to ensure continuous operation of equipment and live data flow. To ensure effective operation of these units, inspectors perform regular visits to the scattered RTU sites to check their operating conditions and ensure that they are providing the correct data in a timely manner. This incurs travel costs and poses safety hazards while also planning these trips were difficult given the large operational area of Saudi Aramco.
Therefore, an IT solution was developed to pinpoint and remotely monitor the status of these RTUs in a web-based Geographic Information System (GIS). Also, e-mail and SMS messages are now generated to alert concerned staff about any unit failures even outside normal working hours. Moreover, a GPS-based AVL (Automated Vehicle Location) application was integrated with this solution to enable a faster response to these RTU failures by determining the nearest field maintenance or inspection crews. This integrated solution helps to provide a real time status of all field installed RTUs, optimize the field inspection and maintenance trips, thereby reducing costs and maximizing unit reliability.
Electromagnetic Methods to Monitor Gas Hydrate Distribution and Production in Layered Sediments
Authors: Enkin R. J. , Hamilton T. S. , Wright J. F. , Kilduff M. , Bild-Enkin D. J. 
Published: February 2011

Abstract
Natural gas hydrate reservoirs are hosted in heterogeneous sediments having variable pore fluid salinity. Questions concerning GH formation, detection and production are being addressed and measured in real time with simple laboratory apparatus. Our vessel is pressurized with methane and monitored with individually calibrated pressure transducers and thermistors. The silt or sand pack is assembled using uniform grain size layers containing ~20% by weight of pore fluids. This results in mixed wettability, with pendant water and initial partial gas saturation. Sand packs consisting of silica silts, sands, and charcoal were selected to emulate the dominant lithofacies observed in the Mallik gas hydrate reservoir. Fluids range from distilled-water to 37ppt salinity. A central needle probe permits the measurements of electromagnetic signals across the specimen. Formation of GH alters the bulk dielectric constant of the mixture, through the conversion of water to gas hydrate crystals and or ice. The infilling of primary porosity by gas hydrate or water ice tends to reduce permeability and increase electrical resistivity, while the expulsion of solutes by hydrate or ice formation decreases resistivity by building a salt bridge along alternate permeability paths. Four methods monitored GH formation and dissociation: 1) Deposition or evolution of gas derived from measurement of the ambient pressure and temperature; 2) Calorimetric measurements of latent heat production by exothermic crystallization and consumption by endothermic dissociation; 3) Time-Domain Reflectometry (TDR) measurement of the velocity of electromagnetic signal propagation and reflections at boundaries in the sand pack; 4) Electrical Impedance Spectroscopy (EIS), a frequency domain method permitting direct measurement of the resistance and capacitance spectra. Improvements in real time digital monitoring and data analysis have made possible the recognition of TDR reflections previously considered unattainable in the presence of conducting fluids. The independent monitoring methods, with their various temporal and spatial sensitivities, capture the intricate details of GH formation and dissociation as a time series. In more porous and permeable beds, GH formation as evidenced by a coherent pressure drop and thermal pulse precedes the increase in electrical conductivity and dielectric constant. These results are interpreted to be the result of a diffusive pulse of solute exclusion from the GH-bearing layer into neighbouring sediment. Measurable EM effects suggest that borehole EIS, with lower frequency and greater penetration than TDR, may be effective for monitoring the variable position of GH-Methane interfaces during GH production tests.
Optimized Steam and Condensate Systems in Refineries: How to Improve Operational Reliability / Safety and to Decrease Energy/Water Consumption and CO2 Emissions
Authors: Ivanov Rossen 
Published: February 2011

Abstract
An optimal management of the steam and condensate system in refineries and petrochemical plants has a direct impact not only on safety, but also on the operating costs of the plant. The production down-time due to failures of the steam system is probably the main cost-driver in this analysis. The abnormal failure of equipments and the resulting maintenance costs could also have an important financial impact. Even if the decrease of these costs is difficult to predict in advance, different case studies show the important damages and their financial impact once the failure has occurred.
The decrease of the energy and water consumptions and the related CO2 emissions is easier to establish. Based on the auditing work done in refineries and petrochemical plants, it appears that more than 5% of the yearly steam cost and related CO2 emissions could be saved by optimizing the efficiency of the steam and condensate system. The increase of the condensate return rate could allow saving up to 50% of the quantity of boiler feed-water used prior to the optimization. Higher rate of condensate returning to the boiler means also less water poored on the ground or in the sewer, which also has an environmental impact.
For an average-size refinery with a capacity of 150 000 barrels/day, the total saved costs represent typically several million dollars per year.
Bacterial Survival in Fractured Shale Gas Wells of the Horn River Basin
Authors: Moore S. L. , Cripps C. M. 
Published: February 2011

Abstract
Traditional ideology on the upper temperature limits of life, suggest that extreme temperatures like those observed in the Horn River Basin shale gas formation (i.e. up to 175°C), should alleviate microbiologically influenced corrosion and souring concerns associated with hydraulic fracturing procedures. The present case history investigates the accuracy of this theory. Horn River Basin wells currently in the flowback or production stage, and the source water used to fracture these wells were studied for the presence and identity of viable bacteria. The effectiveness of two biocides, a gluteraldehyde-based and a cocodiamine-based, in eradicating these bacteria in both the field and the laboratory, was also studied. The results show that source ponds are highly contaminated with bacteria. Furthermore, the high-temperature, high-pressure downhole conditions in this region are not sufficient for eradicating bacteria introduced during the fracturing process. These bacteria survive and establish viable, proliferating communities. Biocide, applied continuously "on-the-fly" during fracturing, was effective at mitigating the downhole bacteria concern. Laboratory study further showed that more established bacterial communities were much more resistant to biocidal treatment. Therefore, early mitigation strategies will likely be key in the prevention of microbiologically induced corrosion and souring.
Optimizing Injection Wells through Innovative Completion
Authors: Khalil Ashraf , Elasmar Magdi , Shafie Shaiful 
Published: February 2011

Abstract
This paper covers the first global application of Influx Control Device (ICD) in an injector well for carbonate formation. This inventive completion coupled with a wellbore simulation will optimize the injection profile into heterogeneous formation zones hence enabling reservoir management strategy to be achieved.
Carbonate formations are typically known for their heterogeneity and complex pore system which have an impact on the fluid movement pathway. Conventional injection wells face the challenge of achieving even distribution of the injected water along the wellbore. Heel to toe effect, significant permeability contrast and existence of thief fractures is among the factors that complicate the effort to achieve a good reservoir management.
Inflow control devices have a long history of application in production wells both in sand stone and carbonate formations. It has proven to be very effective in achieving a balanced inflow profile along the horizontal section, delaying water and gas production breakthrough. The Influx Control Device is equally able to function in an injection well and with the usage of wellbore simulation, is able to cater for the complexities of the carbonate formations.
The installation was carried out in a horizontal water injector well in a major oil field, offshore Abu Dhabi. This paper presents the design of the completion, its installation and the initial water injection results based on production logs.
The positive result from the installation has shown the applicability of such completion technology and offers solutions in our effort to optimize reservoir performance particularly in carbonate formations.
Method to Improve Thermal EOR Performance Using Intelligent Well Technology: Orion SAGD Field Trial
Authors: Clark H. P. , Ascanio F. A. , Van Kruijsdijk C. , Chavarria J. L. , Zatka M. J. , Williams W. , Yahyai A. , Shaw J. , Bedry M. 
Published: February 2011

Abstract
A method has been developed for improving both steam injection and production conformance in a thermal EOR project by utilizing intelligent well technology incorporating interval control valves (ICV), well segmentation and associated downhole instrumentation. This provides the ability to selectively open and close segmented sections of the well bore and monitor the key parameters of temperature and pressure from surface. The initial field trial is ongoing in the injector of an Orion field SAGD well pair. Development of the completion system suitable for thermal conditions, initial field trial results and plans for further development are described.
Modelling shows that, depending on the level of heterogeneity present in the reservoir, an improvement of 20 to 40% in the steam oil ratio and 5 to10 % in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost effective solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is applicable to a wide range of EOR processes such as CSS, steam drive and variations.
The initial field deployment in the injector well was primarily to prove operability of the system in high temperature thermal applications, to demonstrate the feasibility of modifying steam distribution and to learn for future optimization and deployment of the system. A successful installation and commissioning has substantially validated the completion technology. Early injection test results and data provide a significant improvement in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of steam injection in the well is underway and the preliminary results are discussed. Lessons learned from the trial are highlighted.
The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects to improve performance.