bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Histories of Improved Horizontal Well Cleanup and Sweep Efficiency With Nozzle Based Inflow Control Devices (ICD) in Sandstone and Carbonate Reservoirs
Authors: Raffn Anne Gerd , Zeybek Murat , Moen Terje , Lauritzen Jon Eric , Sunbul Ahmed Hassan , Hembling Drew E. , Majdpour Abdi 
Published: October 2008

Abstract
This paper discusses the PLT-correlated results of two test wells completed during 2006; one in sandstone and one in a carbonate reservoir, with the new completion technology of nozzle-based passive inflow control devices (ICD) which improves performance of wells with reservoir challenges as described:In highly productive sandstone reservoirs, horizontal wells suffer from uneven flow profile and subsequent premature cresting/coning effects. In general, there is a tendency to produce more at the heel than at the toe of horizontal wells, which contributes to poor well cleanup at the toe. Additionally, excessively increasing the rate and/or horizontal well length can increase the risk of limiting sweep efficiency, resulting in bypassed reserves1.In carbonate reservoirs, permeability variations and fractures can cause uneven inflow profile and accelerate water and gas breakthroughs. Wells with early gas or water breakthrough have to be shut-in until remedial plans are decided and implemented, resulting in deferred production.
The main reservoir objectives for applying passive ICD technology in the two test wells are:Sandstone: Decrease the influence of heel-toe effects and high permeability zones; hereby deferring water/gas breakthrough, improving well cleanup and sweep efficiency.Carbonate: Control flow rates from high permeability intervals and to limit production from each compartment based on lateral offset from the gas-oil contact to prevent premature gas breakthrough.
The test well PLT-logs were correlated to static reservoir simulations. Analyses of the well performances show that the objectives of both completions were achieved. By having proper matches of the completions with ICD, the value over standard completions can be evaluated.
Post-evaluation of the completion designs based on the PLT-log results has increased our understanding of the nozzle-based ICD performance. As a result several approaches for completing wells in both sandstone and carbonate reservoirs with ICD have been recommended in order to achieve optimized inflow performance.

Introduction
Two trial wells with nozzle-based passive ICD systems were designed and completed in 2006; one for sandstone and one for carbonate reservoirs. To evaluate and approve the new ICD completion, these wells were production logged and the results were carefully analyzed.
The most important feature of the ICD completion is the self-adjusting effect of flow variations anywhere along the well trajectory and whenever they occur during entire well life. The key benefits are:Increased well life and reserves due to improved sweep efficiency.Delayed gas and water breakthrough.Decreased water/gas rates after breakthrough when water/gas mobility is higher than oil.Improved well cleanup.
Small Field Development and Subsea Tieback Technologies
Authors: Hawkins David W. , Chipman Wayne Ivan , Dillabough Graham D. , Ruelokke Max , Way Fred 
Published: October 2008

Abstract
Twenty-four oil and/or gas discoveries have been made offshore Newfoundland and Labrador. Three of the oil discoveries have been developed and a fourth is under consideration. The focus of development activity has been on the larger oil discoveries. As production from the larger discoveries matures, facilities and other infrastructure will become available for development of the remaining smaller discoveries. Development and tie-in of smaller pools and fields provides an opportunity to utilize this spare production capacity at these fields. Currently, there are several satellite tie-in and expansion projects in progress and others are under review. Development of the discovered smaller fields will play an important part in sustaining production from offshore Newfoundland and Labrador. In addition, many of the offshore basins are under explored and represent other opportunities to supply the next round of developments.

Introduction
Newfoundland and Labrador, Canada's easterly province (Fig. 1) is strategically positioned on international shipping lanes, with unique access to global petroleum markets.
Arthit Field Development: Float-over Hardware Design and Issues
Authors: Tan Boon-Sze , Sahasrabudhe Sanjay , Haney James Allan , Leow Bee-Lay 
Published: October 2008

Abstract
The 17,500 metric ton Arthit PP topsides was successfully installed in December of 2007 in the Gulf of Thailand after a short voyage from Batam Island, Indonesia, where the topsides was fabricated. The topsides was installed in one piece using the float-over method. Three types of hardware components were designed and fabricated to facilitate the float-over. One type supported the topsides during the loadout, transport and float-over. The second type provided the interface between the topsides legs and the jacket. The third type was mounted on the pile tops and provided landing receivers for the topsides legs and final leveling and joining features. The design, fabrication, and operation of these three components will be discussed in this paper.
The float-over hardware components are designed to suit the " loose slot method?? of topsides float-over installation and rapid ballasting system of the transport barge. Arthit PP topsides float-over experience shows that float-over hardware components can be designed and implemented for offshore installation of large topsides.

Introduction
The installation of single piece, large-sized topsides by float-over method is a cost effective alternative since it minimizes offshore hook-up and commissioning. Various float-over methods and associated challenges are described in paper OTC 19072 by Seji and de Groot (2007). Installation of large topsides tends to produce large mating forces and relative displacements; thus placing high design requirements on sub-structure and topsides. A means of facilitating rapid separation of transportation vessel from underside of the topsides was vital for a successful float-over. The float-over hardware is essentially provided to reduce mating forces, accommodate large relative displacements, provide effective cone capture mechanism, and facilitate rapid separation of transport vessel and topsides.
During recent float-over installation of Arthit topsides, the transport barge was not guided by bumpers mounted on the jacket during the barge entry and exit from the jacket " slot??, or during the actual float-over operation. The mean position of the barge was controlled by a primary mooring system fixed to the sea floor plus a tug during entry and exit. In the float-over position a secondary mooring system of soft lines was designed to connect the barge to the jacket. The barge orbited in the slot without touching the jacket. This float-over concept is called the " loose slot method?? and is described in paper OTC 19230 by Kocaman and Kim (2008). This concept is the preferred method at J. Ray McDermott (J. Ray) since it minimizes barge contact with the jacket during slot entry and exit.
A rapid ballasting system was installed in the transport barge Inermac 650 during a dry-dock. The system is designed to separate the barge from the topsides in less than twenty minutes (OTC 19231, Kim et al, 2008). The rapidity of the ballasting reduces risk level during the float-over operation.
A General Method for Subsurface CO2 Storage Capacity Calculations
Authors: van der Meer Lubertus , Egberts P.J.P. 
Published: October 2008

Abstract
It is neither straightforward nor simple to estimate the capacity of a geological formation to store CO2. In a recent attempt to list the various estimates of CO2 storage capacity for the world and regions of the world (Bradshaw et al., 2006), the estimates are often merely given as " very large??, with ranges in the order of 100s to 10,000s Gt CO2. It is clear that there is a general lack of definitions, rules and general procedures for calculating storage potentials.
Having conducted studies in the past, TNO is convinced that we now need a more uniform and standard method to calculate the storage potential of any subsurface location - be it a gas or oil field (whether totally or partially depleted) or an aquifer. In any calculation of storage capacity, TNO prefers to include the concept of total affected space i.e. the entire space whose state or qualities change during the total storage time as a result of the storage operation. Furthermore, in the storage calculations we consider the injectivity of the selected injection location, and the pressure and fluid conductivity of the total affected storage space.. The intended free CO2 storage location must have enough storage space or enough sealing capacity to contain the CO2 for at least 10,000 years and prevent it from migrating to the surface. And finally, it must be taken into account that as a result of gravity segregation, the heavier CO2-saturated formation water will sink to deeper parts of the affected space.
We describe a standard method we have devised to be used for any storage location to calculate the maximum storage volume based on affected space and maximum pressurization, the storage potential based on injectivity, and finally the storage efficiency of the geological trap.

Introduction
We often need to know how much CO2 we can store in a certain underground space, or how much such space we need to store a given amount of CO2. In a recent attempt (Bradshaw et al., 2006) to list various regional and global estimates of CO2 storage capacity (figure 1), the estimates reported are often quoted as " very large?? with ranges in the order of 100 to 10,000 Gt of CO2. From the publications Bradshaw and his colleagues consulted it is clear that there is a lack of definitions, rules and general procedures for calculating storage potentials. The calculations of CO2 storage capacity are mainly based either on the solubility potential (Bachu et al., 2003) and ignore volumetric consequences and the kinetics of this process, or on a fixed percentage of a subsurface volume (Koide et al., 1992). None of the cases using the latter approach include any definitions. In this paper we will specify a method to calculate the Theoretical Maximum Storage Capacity. We will give comprehensive definitions of all the important parameters in a separate and upcoming publication. In the present paper, the parameters appear in italics. They are briefly described below.
Leak Detection in Subsea Pipeline: A Mechanistic Modeling Approach With Fixed Pressure Boundaries
Authors: Gajbhiye Rahul Narayanrao , Kam Seung Ihl 
Published: October 2008

Abstract
A subsea pipeline leak has caused a serious concern over the transportation of deepwater oil and gas production to onshore or shallow-water production facilities. Hazardous impact on marine environment and consequential economical loss resulting from the subsea pipeline leak became an important issue of oil and gas industries. Currently more than hundreds of hydrocarbon production projects are ongoing, and deepwater production is expected to almost double over the next decade in the Gulf of Mexico. Active development of deepwater activities in the Gulf of Mexico will undoubtedly lead to the expansion of subsea pipelines.
This study, for the first time, shows how a subsea pipeline leak can be modeled in a mechanistic way. Especially, a focus is made to the implication of fixed-pressure boundary conditions at both upstream and downstream locations, which is quite relevant to the way how the majority of field operations are actually operated and managed. The use of fixed-pressure boundary conditions leaves the change in inlet total flowrate (Dqtin) and the change in outlet total flowrate (Dqtout) as two possible leak detection indicators that can be monitored on real-time basis. The two-phase flow in subsea pipelines, which is filled with gas and oil mixtures, is analyzed using well-known Beggs and Brill's two phase correlations. The effect of different parameters on the mechanistic leak detection modeling is investigated accounting for gas compressibility, back pressure of the system, the pressure drop across the system, input fraction of gas and oil phases, and the fraction of gas and oil phases leaking out of the pipeline system through the leak.
The results exhibited the following outcomes:The leak could be more easily detected with increasing leak size no matter which of the two leak indicators (Dqtin or Dqtout) were used;The presence of compressible fluid in the pipeline amplified the disturbance to the system in general. This made the use of Dqtout less promising (but the use of Dqtin more promising at the same time) for leak detection;The loss of larger fraction of less dense and less viscous fluid through the leak caused the use of Dqtin less viable but the use of Dqtout more viable; andCombination of larger pressure drop across the system (i.e., the difference between the inlet and outlet pressures) and larger gas fraction at the leak (fgleak) made the use of Dqtout more favorable.
It should be noted that the net effect of the presence of gas phase, by taking gas compressibility, viscosity and density all together into consideration (i.e, (2) and (3) above), was a decrease in ?qtin and an increase in ?qtout. This means that the presence of gas phase in the subsea pipelines makes the use of qtout more reliable (but the use of qtin less reliable) as a leak detection indicator.
Comparisons of Various Fairing Geometries for Vortex Suppression at High Reynolds Numbers
Authors: Allen Donald Wayne , Henning Dean 
Published: October 2008

Abstract
Several fairing geometries have been tested with a tow carriage to examine their ability to suppress vortex-induced vibration and reduce drag. The tests were performed in the critical and supercritical Reynolds number ranges with fairing chord-to-thickness ratios ranging from 1.33 to 2.52. Stabilizer fins were attached to some of the fairings, while others had a thin tail or came to a point at the tail. All the fairings were allowed to fill with water and were free to weathervane while towed in a horizontal configuration on a flexible pipe. The results illustrate that larger chord-to-thickness ratio fairings provide lower drag than smaller chord-to-thickness ratio fairings. Smaller chord-to-thickness ratio fairings are most effective when the tail is thin and longer chord-to-thickness ratio fairings can benefit from the presence of a stabilizer fin.

Introduction
Fairings have been used by the offshore oil and gas industry to reduce vortex-induced vibration (VIV) since the late 1970s (see Every and King 1980; Gardner and Cole 1982; and Grant and Patterson 1977). Most early designs had fairly large chord-to-thickness ratios, and their use focused on drilling riser applications. The common wisdom was that fairings were unsuitable for production applications, due to the potential for marine growth to lock them in place or prevent them from weathervaning properly with the direction of the ocean current.
In the late 1980s and early 1990s, the authors, while conducting tests in a current tank, discovered that short fairings can be very effective at suppressing VIV. In subsequent testing over the next several years, the authors discovered that these short fairings were also effective at critical and supercritical Reynolds numbers (Allen and Henning 2003). This short fairing geometry was subsequently used for several deepwater production risers as well as several drilling risers. Most research and development over the next few years was focused on designing this fairing properly to insure its performance, fitness for purpose, and integrity. While development work was done to expand its usefulness to a wide range of tubular installation methods, very little research was performed to produce new fairing shapes that can effectively reduce both VIV and drag.
The objective of this set of experiments was to ascertain the effects of various fundamental geometrical features of fairings on their performance, as measured by vibration and drag reduction. While a systematic approach was desired, it was recognized that a large number of parameters could be varied. These included:The chord-to-thickness ratio;The chord-to-diameter ratio;The presence of a fairing nose and its shape;The shape of the tail (pointed or flat with varying possible widths);The curvature of the two sides of the fairing;The presence of a stabilizer fin;The geometry of the stabilizer fin.
LNG Trials of a New 16' Flexible Hose Based LNG Transfer System
Authors: Rombaut Guillaume , Peigne Alain , Loisel Philippe , Le Cloirec Alain , Machouat Fatima , Maocec David 
Published: October 2008

Abstract
The development of offshore LNG projects, whether for sheltered or harsh environments, represents a vehicle for progress consistent with the LNG market growth and it opens new perspectives and new challenges for the whole LNG Industry. In order to ensure that these new LNG chains will operate correctly and at an optimum rate, the development of an efficient and safe LNG transfer system is a key link, which is still challenging the actors involved in this field.
Since there are several offshore LNG transfer solutions in development, cryogenic flexible hose based LNG transfer systems appear to be able to meet the LNG Industry requirements.
However, in order to demonstrate that a new technology will operate reliably within specific limits, LNG operators generally deem necessary to have either the evidence of such performances through a structured qualification process or to be convinced by significant scale trials in real conditions or close to the ones the system will be used in.
This paper deals with full-scale LNG trials performed in the context of an exiting LNG receiving terminal of a new 16" flexible hose based LNG transfer system designed for onshore and offshore conditions. These trials were the ultimate stage of an industrial qualification of this transfer system and they have been carried out on a unique dynamic test bench able to reproduce open sea conditions in terms of heave amplitude and acceleration.

Introduction
The development of offshore LNG projects is partly based on the ability of LNG industry actors to bring innovative solutions capable of meeting the new technical requirements related to the marine environment. Whether for LNG export or receiving facilities, it appears that the " transfer system?? link is a key element, whose ability to fulfil its role in open sea conditions must contribute to guarantee the availability and flexibility of these new offshore LNG chains.
Gaz de France has undertaken, in partnership with Technip France, KSB and Eurodim, the last stage of industrial qualification of a new LNG transfer system called Amplitude-LNG Loading System (ALLS). This system, based on flexible hose technology and suitable for offshore and onshore conditions, was developed through industrial partnerships involving major oil and gas companies and international certification organizations.
After completion of the technical certification of ALLS main equipment, the requirement to carry out full-scale dynamic testing, with circulation of LNG, was deemed necessary by the LNG operators to demonstrate the performances, operability and safety of this innovative LNG transfer system.
A structured qualification process, managed by Det Norske Veritas (DNV), was then engaged and a full-scale testing programme elaborated with the aim to operate the transfer system in operational conditions with a facility able to reproduce open sea conditions.
Fatigue in Deepwater Steel Catenary Risers: A Probalistic Approach for Assessment of Risk
Authors: Sen Tapan K. 
Published: October 2008

Abstract
Deep water developments are being pursued vigorously in various parts of the world (West Coast of Africa, Gulf of Mexico etc.). The riser system is a critical part of the field architecture. Riser failure results in reduction or cessation of revenue. It may also lead to spillage or pollution and could endanger lives. Hence, riser design must carry a high degree of reliability.
Steel Catenary Risers (SCRs) are considered to be technically feasible and commercially efficient solutions especially when high temperatures and pressures are involved. However, in terms of fatigue, SCRs are very sensitive to environmental loading.
The procedure for fatigue analysis is essentially deterministic.
This paper concentrates on the probability of fatigue failure associated with the design of current practice of fatigue analysis of SCRs. The procedure is illustrated with sample calculations with first order vessel motion and a flow chart for assessing the probability of fatigue failure is also given. The example is chosen so as to highlight the issues involved. The probability of failure is used to determine the ‘safety index’. The probability calculations have been reformulated so that they are applicable for the design of SCRs. The probability of fatigue failure, associated with the recommended factor of safety in API RP 2RD, for the example chosen, is also reported. The overall aim is to increase the confidence in the design of such systems in deep water environment.

1.0 Introduction
A typical SCR attached to a Floating Production Storage & Offloading (FPSO) vessel and part of a deep water field development is shown in Fig. 1. The riser is continuously subject to oscillatory environmental loads. The principal source of structural loading is the ocean waves that impact the riser coupled with the complicated movements of the vessel which itself comprise high frequency response to the waves and low frequency (slow drift) excursion. This paper is concerned with wave induced fatigue only. Stresses resulting from environmental loading and corresponding structural dynamic response at a joint (node) are typically random in nature, as shown in Fig. 2. Metal fatigue in the weld at the joint, due to these oscillatory stresses, is one of the likely causes of failure.
Most vulnerable to fatigue are the welded joints near the touch down point (see Fig. 1) because of high cyclic bending stresses and stress concentration due to both joint geometry and weld defects.
Fatigue life prediction in SCRs is a complicated process involving many factors and has been discussed at length by Campbell (1999). Current practice, mainly deterministic in nature is summarised first.