bluuebunny/crossref_metadata_2025_split huggingface dataset:
Presenting Risks Introduced by Android Application Permissions in a User-Friendly Way
Authors: Varga Juraj , Muska Peter 
Published: March 2015

Abstract
The emergence of Android as a leading Operating System in terms of market coverage induced the rapid emergence of many mobile applications. A lot of these applications are prone to misuse because of their design. This paper deals with a new method of informing user whether applications installed on his device are potentially harmful or not. The introductory part provides some insight into security mechanisms used in Android. The main part deals with research we based our work on, proposal of our own methodology based on permission model and its implementation in application for real-time offline analysis of installed applications on device running Android. The last part of this paper deals with the evaluation of achievements reached by our methodology implemented in standalone application
Low Dosage Hydrate Inhibitors (LDHI): Advances in Flow Assurance Technology for Offshore Gas Production Systems
Authors: Clark Leonard W. , Frostman Lynn M. , Anderson Joanne 
Published: March 2015

Abstract
The use of Low Dosage Hydrate Inhibitors (LDHIs) is one of the optimum methods to control gas hydrate formation issues and provide flow assurance in offshore gas production systems. The application of this technology has several advantages to operators including providing the opportunity for significant cost savings, extending the life of gas systems, as well as providing the option to use combination products. This paper will review the use of Kinetic Hydrate Inhibitors (KHIs) and Anti-Agglomerants (AA) through recent case histories. It will also illustrate how these products can be used in conjunction with Corrosion Inhibitors (CI) as is typically required in gas condensate production systems, either as individual products or as combination products. The novel illustration of the use of LDHIs in sour conditions will also be provided via case histories at low to moderate subcoolings. Hydrates can form different structures depending on the gas composition of the produced fluids. The nature of the LDHI used needs to take this into account and new product developments in this area will be covered.

Introduction
Natural Gas Hydrates. When considering the production of hydrocarbon fluids from offshore gas systems, flow assurance is a significant issue which needs to be taken into account. An important element of flow assurance is the investigation into the possibility of gas hydrate formation and its subsequent control. The inhibition of gas hydrate formation needs to be taken into account as part of the production of offshore gas, especially as hydrates typically form at lower temperatures and higher pressures. Production facilities, particularly offshore wells and offshore transmission lines, may be operating under conditions where hydrate formation is favourable.
Gas hydrate formation occurs when natural gas molecules are surrounded by water molecules to form 'cage'-like structures. Gas hydrates are similar in appearance to ice. Both materials have crystalline structures that exhibit similar characteristics – with the important difference that the natural gas hydrate has a natural gas guest molecule as an integral part of its structure. Examples of typical hydrate forming gases include Nitrogen, Carbon Dioxide (CO2), Hydrogen Sulfide (H2S) and light hydrocarbons (such as methane through to heptanes). Depending on the gas composition and the pressure, gas hydrates can form at temperatures of up to 86 °F where gas co-exists with water.
"On the Fly" Stratigraphic Basin Modelling From Seismic Interpretation Workstations
Authors: Albouy E. , Cacas M.-C. , Dobranszky G. , Laigle J.-M. 
Published: March 2015

Abstract
Seismic intepreters already use the principles of sequence stratigraphy to help interpret the geometry and sedimentary facies of the sedimentary bodies seen on seismic data. Linking seismic interpretation to a well database containing information on bathymetry and lithology, by using ultra-rapid algorithms simulating sediment transport, can help the interpreter to rapidly test and modify the stratigraphic scenario inherently present in the geometry and nature of the surfaces that have been picked. This "on the fly" stratigraphic modelling should make seismic stratigraphic interpretation easier and simpler to perform.
Various image-processing techniques can also be of help to the interpreter, both in determining depositional environment from seismic textural analysis and in a more rapid identification of the key toplap, onlap, downlap and truncation surfaces present in the seismic data. Again, linking the textural information with the well database can lead to a better use of both types of data.
The above techniques have been applied to seismic and well data of the National Petroleum Reserve Alaska, as a structured workflow involving the construction of a detailed geomodel and time-to-depth conversion cube. For each of the sequences picked on the seismic, the direction and composition of the principal sources of clastic supply are determined, and paleobathymetrical maps are generated, all of which are coherent with the well data (interpreted lithology and depositional environment) and the picked thickness of the sequence on seismic. The interpreter can then choose to view the seismic data of the next sequence in «true stratigraphic position» by shearing to fit the modelled bathymetrical profile of the underlying sequence. He or she may also choose to review and reinterpret the well data or repick the seismic surfaces in the light of the realistic paleogeographical scenario generated by the stratigraphic modelling.

Introduction
The aim of the present work was to test the application of algorithms designed to assist seismic interpretation for petroleum exploration by using the principles of forward stratigraphic basin modelling. We used a data set from the North Slope, Alaska which is freely available online from the United States Geological Survey (see below). The data to be fitted by the stratigraphic forward modelling included the thickness of stratigraphic intervals between markers picked on seismic data, the bathymetry and the lithological content of these interval identified in wells.
Coiled Tubing Deployed Bottom Intake ESP Developed for Al Rayyan Field, Offshore Qatar ... Nine Years of Experience
Authors: Hood K. , Sanden J. 
Published: March 2015

Abstract
This paper presents a review of a coiled tubing deployed, bottom intake (CTDBI) electrical submersible pump system (ESP) developed specifically for use in the Al Rayyan Field, offshore Qatar. The evolution of this technology to its present form will be reviewed along with the systematic approach used to enhance the original design and improve system run life. Also presented are workover, operational and economic considerations as compared to conventional ESP systems commonly run offshore. The review will also include the well completion design and how it functions and accommodates the ESP.

Introduction
Al Rayyan Field is located approximately 45 miles off the northern coast of Qatar in the Arabian Gulf. The field was discovered in 1976, however commercial development did not begin until 1996 through the application of horizontal drilling. Oil production is from carbonate reservoirs that require artificial lift. With its relatively low GOR and low bottom-hole temperature, Al Rayyan was an ideal candidate for ESP's.In order to be economically viable, the field development plan called for high production rates as well as a work over process that was more cost effective than conventionally deployed ESP systems requiring a drilling rig to pull and run. Al Rayyan Field currently has 13 producing horizontal wells, all equipped with CTDBI ESP's.
In 1996 the CTDBI ESP system was the first of its kind to be deployed. The key drivers behind developing this technology were to reduce workover cost and improve ESP availability with an ultimate goal being to achieve better overall project economics. In a typical conventional ESP system, the ESP string is run on jointed production tubing with a power cable strapped to the outside. The produced fluid reaches the surface via the conveyance tubing for which a drilling rig or pulling unit is required to run and pull. In the conventional ESP system the motor(s) are placed at the bottom of the ESP string, while in the CTDBI design the motor(s) are at the top. This difference makes the system unique and is why it is termed "bottom intake" (Figure 1).
Geomechanical Modelling of a Pore Collapsing Carbonate: Compaction and Subsidence of a Field in Oman
Authors: Dudley John Wesley , van der Linden Arjan , Mueller Guy Francois 
Published: March 2015

Abstract
A field in Oman provides a good example of compaction and subsidence due to a pore-collapsing carbonate formation. The field is comprised of a gas reservoir in the Natih formation and an oil reservoir in the deeper Shuaiba formation. Both reservoirs are formed by high porosity carbonates that can display a highly compressible "pore collapse" response with depletion. Both reservoirs are in production. Gas production from the Natih reservoir started in the early 70's, and continues at present from a dozen wells producing from the center of the field. Oil production from the underlying Shuaiba reservoir began in the late 60's, and the field has been under waterflood since the early 70's. All 450+ Shuaiba producers/injectors are drilled through the compacting Natih reservoir. Compaction damage to these oil wells is a major incentive for understanding the compaction and subsidence in this field. This paper presents the results of a detailed geomechanical study done to predict subsidence and compaction for the field. Core, log and field data are all incorporated to create a calibrated 3D geomechanical model for predicting ongoing field subsidence and estimating compaction potential. Key to this is an understanding of the field geology and diagenetic controls on rock strength and compaction in the Natih reservoir. Core compaction tests show the reservoirs are highly compressible pore collapsing carbonate formations. Although this is highly non-linear compaction behavior, in-situ field compaction measurements show an averaged, more linear response This fact advocates against using a 'pore collapse trend' to predict in-situ compaction. The measured field subsidence in the late 1990's & early 2000's is successfully predicted assuming an average linear material response, provided the variable diagenetic character of the field is honored for the pore-collapsing facies. Extrapolation of the model indicates compaction strains at the end of field life in the order of 5% in the crest of the field and a maximum subsidence of about 2 meters.
Large LNG Ships - The New Generation
Authors: Greer Matthew Noble , Richardson Andy J. , Sandstrom Robert E. 
Published: March 2015

Extended Abstract

Introduction
Qatargas II (a joint venture of Qatar Petroleum and ExxonMobil) and ExxonMobil have collaborated to develop and implement a new generation of larger, more efficient LNG ships. They will be industry's first LNG ships with cargo capacities greater than 200,000 m3 (Figure 1). Through the application of several new technologies for LNG ships, along with optimization of marine systems and transportation efficiencies, this new generation of ships represents a significant step change in reducing the cost for delivery of liquefied natural gas to markets worldwide.
This initiative represents a key element of the Qatargas II project, whose goal is to develop 15 MTA of gas from the Qatar North Field. While the geographic location of the Qatar gas resources allows sales to both the East and the West, the remoteness from new markets in Europe and America calls for innovation and integration across the full value chain in order to achieve project success. For the transportation element of this value chain, the focus has been on how to achieve economies of scale and efficiency improvements via large ships.

Industry Settings and Drivers for Large LNG Ships
Industry relies on an LNG shipping fleet that has evolved considerably over the last fifty years. From the early 1970s through the mid-1980s, the fleet experienced steady growth (Figure 2). Following a period of relative stability in the mid-1980s, the fleet again saw significant growth that continues today. Interestingly, although the number of ships in the fleet has increased considerably, cargo capacity for new LNG ships has remained relatively stable for the last 30 years (Figure 3). A significant increase in cargo capacity from roughly 75,000m3 to 140,000m3 was realized in the mid-1970s and has remained the standard until only recently.
Saharan Aquifers Protection in Oil and Gas Upstream Activities in Algeria: A Sustainable-Development Challenge
Authors: Okba Dhina 
Published: March 2015

Abstract
In the south of Algeria – where almost all oil and gas upstream activities are carried out – Non-renewable groundwater preservation remains the most important challenge given the water scarcity Algeria is beginning to face.
The aim of this paper is to point out how manageable it is - for an oil and gas company - to reach its main objective as an industrial company without jeopardizing these valuable resources.
Contamination and overexploitation are the two major threats to be taken into account when dealing with Northern Sahara Aquifers System (NSAS) protection. Thus, Groundwater preservation includes both protection against contamination and water use optimization.
Besides, well construction quality and integrity are decisive conditions to efficiently prevent any contamination risk during both drilling and producing phases. Hence, regarding well construction, FMEA risk analysis method is fit for purpose to consider all potential failure modes and their effects that might endanger these aquifers.
On the other hand, standardization efforts have to take into account the contrasting aspect of the environment within the whole country. Sahara, in deed, represents a singular ecosystem with its own characteristics and vulnerabilities. Such diversity is seen as a real challenge when elaborating and fulfilling standards.

Introduction
Algeria's economy is still substantially relying on oil and gas sales that consist of 98% of the total exports earnings and contribute to 35% to the GDP. Thus, the main task Sonatrach has been entrusted with is to generate wealth to kick-start the development process.
Although Sonatrach is well established countrywide, upstream activities (exploration, drilling and production) are mainly performed in the south – Hassi Messaoud being the main oilfield – where strategic groundwater reserves spread out. These reserves are well-known as the "Northern Sahara Aquifers System" (NSAS).
To correctly figure out the vital importance of the NSAS, it sounds of great helpfulness to remind that Algeria belongs to a dry region of the world that is facing a severe water shortage. Thus, the challenge for Sonatrach is to optimize oil and gas production operations, keeping in mind that the NSAS valuable reserves might be protected and preserved.
Reservoir Connectivity in a Complex Fractured Reservoir: The Relationship Between Fracturing and Facies in the Upper Cretaceous Apulian Platform of the Maiella Mountain, Southern Italy
Authors: Di Cuia R. , Gout C. , Balzagette L. , Masse P. , Vieban F. 
Published: March 2015

ABSTRACT
Understanding connectivity in complex, low-porosity, fractured carbonate reservoirs is fundamental for the correct assessment of their potential. In this kind of reservoirs, fracturing is essential. It is very difficult, using only subsurface data, to correctly define the 3D distribution of the fracture network because the characteristics as fracture density and fracture type are often doubtful.
The Upper Cretaceous Rudist Carbonates of the Apulian Inner Platform represent a superb reservoir for some of the most prolific southern Italy HC fields (figure 1). This reservoir is deeply buried underneath a thick pile of allochothonous thrust sheets but the outcrop equivalent in the Maiella Mountain allow to study its 3D architecture and characteristics.
Fracturing is not randomly distributed but the pervasive fracture distribution at bed scale (background fractures) is closely related to the distribution of different sedimentary facies.
This relationship is a key starting point to correctly model the reservoir behaviour in terms of three-dimensional connectivity (fracture connectivity network) and of identification of potential fracture-related good hydrocarbon storage intervals.
The multi-disciplinary outcrop acquisition method and integration used for this study are innovative: they are designed to get the most interactive contribution between sedimentary, stratigraphic, mechanical and structural analysis.
Generally, fine-grained sedimentary facies (the more abundant and continuous in the inner platform) are characterised by higher fracture densities (for all fracture orders). In such sedimentary facies, typical fracture sets are often sub-parallel and bed-confined. These facies, with higher fracture porosity could represent important HC storage intervals within the reservoir.
Laterally discontinuous coarse rudist associations and coarse-grained sedimentary facies are characterised by scarce fracturing but also by relatively good matrix porosity. These facies can also be considered as good HC storage intervals which could be isolated from the rest of the reservoir.
Managed Induced Fracturing Improves Waterflood Performance in South Oman
Authors: Saeby Jan , Bjorndal Hans-Petter , van den Hoek Paul 
Published: March 2015

Abstract
Novel modelling technologies that includes induced fractures in a dynamic reservoir simulator has been used to analyse subsurface aspects of an inverted 5-spot injection pilot. The techniques have allowed an accurate depiction of growing induced fractures. Simulation results indicate that induced fracture growth is limited at injection rates &lt; 200 m3/d but that higher injection rates will result in fracture propagation and a risk of rapid water breakthrough. The results have been validated by field observations. A controlled and cautious increase in injection rate has resulted in a positive production response with rate increases of 50–100% in three of the four producers in the pilot.
Results from the pilot have increased the current reservoir understanding and reduced subsurface uncertainties. The knowledge gained is being included in an updated Field Development Plan that will be issued in 2005. The plan will incorporate an optimised injection strategy by a careful and controlled ramp up in injection rate. This project has also advanced induced fracture research with a field verification of the predictive capabilities of the modelling technology.

Introduction
The Marmul Haima West sandstone reservoir in South Oman, containing heavy and viscous crude (22 ºAPI, Î¼o = 90 cP) and on production since 1980, was initially developed on depletion/solution gas drive using vertical wells. To boost production and improve recovery, an aggressive waterflood development using horizontal wells was initiated in 1999. The development was, however, stopped prematurely in 2000 after excessive induced fracture growth resulted in water short-circuiting and poor well performances.
To improve subsurface understanding and redefine a development strategy, an inverted 5-spot produced water injection pilot project was initiated in 2002 with the procurement and construction of dedicated water cleaning and injection facilities and drilling of 5 new vertical pilot wells (i.e. wells I-1, P-1, P-2, P-3 and P-4). A map of the field and the placement of the 5-spot pilot have been shown in Figure 1.
Acid Gas Injection Facilities for Gas Disposal at the Shute Creek Treating Facility
Authors: Wall Robert A. , Kenefake Daryl A. 
Published: March 2015

Abstract
Acid Gas Injection (AGI) facilities have been constructed and are currently being commissioned at the ExxonMobil Shute Creek Treating Facility in Southwestern Wyoming, United States. The successful startup of the Shute Creek AGI facilities will demonstrate the feasibility of using AGI compression, liquefaction, and pumping technology on large scale projects to dispose of waste acid gases.

Overview
This paper discusses the purpose of AGI facilities at Shute Creek and provides an overview of the equipment and processes implemented in the Shute Creek facilities which include acid gas compression, water removal, liquefaction, and pumping. Commissioning of facilities on CO2 and safety considerations of the AGI facilities are also discussed.
This paper has been prepared for presentation at the International Petroleum Technology Conference (IPTC) in Doha, Qatar scheduled for November 21–23, 2005.

Background
Purpose of AGI. The AGI facilities at Shute Creek Treating Facility are intended to replace aging Claus sulfur recovery units. Installation of the AGI facilities will eliminate bottlenecks and avoid downtime associated with the sulfur recovery units. In addition, the AGI facilities allow Shute Creek Treating Facility to exit a historically weak Sulfur market and reduce SO2 emissions.
The AGI facilities at Shute Creek consist of centrifugal compressors, centrifugal pumps, coolers, separation equipment, pipelines and wells to dehydrate and inject acid gas generated in the gas sweetening process. An overall block flow diagram of the Shute Creek AGI facilities is shown in Figure 1. In conjunction with the installation of the AGI facilities, Cogeneration facilities were also installed to generate steam and power for plant consumption.
Unique Characteristics of the Shute Creek AGI Facilities.
There are currently about 80 AGI plants in operation throughout the world. Most of the operating facilities are located in Canada and the United States; however, about 10% of operating AGI facilities are located outside of North America. Most AGI facilities constructed to date consist of reciprocating compressors discharging directly into injection wells. AGI facilities in North America typically have design capacities of less than 5 MCFD. The Shute Creek AGI facilities are anticipated to be the largest in the United States with a design capacity of 65 MCFD of acid gas composed primarily of Hydrogen Sulfide, H2S and Carbon-Dioxide, CO2.