bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deepwater Ocean Currents West of Britain: Measurements & Criteria Development
Authors: Spring Walt , Gu George , Gray Mike , Middlehurst Bill , Dello Stritto Frank J. 
Published: October 2008

Abstract
Tranche-6 in the Færoe-Shetland Channel is a deepwater site characterised by complex currents of potentially high magnitude. Preparation for drilling at Tranche-6 included development of extreme and operational environmental criteria. Wind and wave conditions could be estimated with adequate accuracy from existing hindcast studies. Information on ocean currents is in general lacking, and hindcast modelling for currents is not nearly as accurate as for waves. Measurement programs collected data near the site in June-November 1992 and April-September 1995. Recorded data confirm strong currents varying in direction with depth. The data are the basis for preliminary extreme criteria and generic current profiles used in operability studies. Realtime current measurements were also made during Tranche-6 drilling, which began in May 1998, to support station keeping and riser management decisions. A weakness in advisory capabilities exists due to the lack of reliable current forecasts.

Introduction
This paper summarises (1) ocean current data collection and criteria development in preparation for drilling activities at Tranche-6 and (2) measurement and use of current data during drilling.
The UK Frontier Licensing Round of June 1991 awarded the Tranche-6 blocks, in the Færoe-Shetland Channel, west of the Shetland Islands, to a partnership of Mobil North Sea Ltd operator), Elf Enterprise Exploration plc and Lasmo North Sea plc. The 11 lease blocks comprising Tranche-6 are UK 213/18, 19, 20, 23, 24 and 214/11, 12, 13,16, 17 and 18 (Figure 1). Tranche-6 water depths range from 1,100 to 1,500 metres (~3,600 to 5,000 feet). Since 1972 more than 140 wells have been drilled West of Shetland. Approximate water depths for most of these wells have ranged from 120 to 800 metres (400 to 2,600 feet). In late 1996, Shell drilled in 1,100 metres (3,700 feet) of water, in a block adjacent to Tranche-6. Drilling at Tranche-6 began in May 1998, from the semi-submersible, Jack Bates, in ~1,200 m of water.
To prepare for drilling at a deepwater, high current severe environment site, preliminary and feasibility studies, including current measurements at the site, were undertaken in 1992 through 1994. Throughout 1995 definition engineering studies and additional current measurements furthered preparations for drilling at the site. The study results were implemented throughout selection of the optimum vessel, acquisition of the necessary hardware and systems (ie, riser fairings, riser and casing restraint systems, station keeping advisory system, and enhanced ROVs), upgrades to the vessel, and development of operating procedures [1].
As of January 1999, two wells have been drilled at Tranche-6, both in approximately 1,200m. For both, real-time current measurements were made to support drilling and vessel operations. To avoid disruption to drilling, a unique deployment of instrumentation was attempted, with varying success as described in a later section.
Ursa TLP, Tendon & Foundation Design, Fabrication, Transportation and TLP
Authors: Digre Kris A. , Kipp Robert M. , Hunt Rupert J. , Hanna Shaddy Y. , Chan Jack H. , Rosen Vic , van der Voort Cees 
Published: October 2008

ABSTRACT
Ursa is the largest TLP in the Gulf of Mexico having 98.000 tons displacement and is the deepest TLP in the world located in 3,800 feet-of-water, MC Block 809. The URSA tendon and foundation design, fabrication and installation were built on the wealth of experience of previously installed TLPs1,2,3,11. In this paper, we focus on the new challenges that had to be met for this record setting project. Unique features of the Ursa Tendons, Foundation and Installation include:More tendons, 16 (4/corner) versus 12 (3/corner);Larger tendons, 32"OD × 1.5" wall (compared to the previous 26" × 1.3" and 28" × 1.2" wall)Longer Tendon Main Body Sections than the previous TLP's, resulting in 283.5' individual sections. This reduced the number of connections required and offshore handling time.New tendon top connector devdoped for Ursa resulting in simpler operations and significant cost savings.The foundation system consists of 16 individual piles. They are 417' in length and 96" OD constructed from 60-ksi material.The potential for significant fatigue-damage accumulation due to pile driving required special design and fabrication solutions.Design, Construction, and Installation strategy developed early on helped reduce cycle time, cost, and accommodated changes during construction.On site temporary mooring of the TLP was accomplished using a Flex-Yoke system.Improved procedures for tendon handling, stabbing and tensioning were developed.

Introduction
The Ursa TLP tendon, foundation and installation design and fabrication extended over a period of 3 years. In order to meet the fast-tract project schedule, material orders had to be placed early, before design completion. Design decisions were focused on reducing both cost and schedule, taking advantage of learnings from the previous TLP's, Early attention was given to the TLP installation design to allow modifications to be incorporated into the planned schedule, tendon design and pile driving requirements.
The modification brought out by the site and water depth change6,7,9 were significant. New soil information had to be obtained, designs verified, installation procedures adjusted and schedules maintained.

Tendon Design, Fabrication and Transportation

TLP and Tendon Sizing
After concept selection in the summer of 1995, the TLPSIZE program was used to size and optimize the URSA TLP. For the initial site, the water depth was determined to be 3,950 feet. Later, due to the site relocation, the water depth was reduced to 3,S00 feet7. Cost optimization was focused on sizing the hull and tendons such that the minimum tendon bottom tension was slightly above zero and the tendon met stress, collapse, and fatigue design criteria with minimal steel cross section area and maximized buoyancy. The program was calibrated based on technical and cost data from the MARS TLP.
Comparison between Observed and Predicted Characteristics of Fatigue Cracks in North Sea Jackets
Authors: Vårdal O.T. , Moan T. , Hellevig N.-C. 
Published: October 2008

Abstract
This paper presents a method which utilises the inspection history / in-service observations to measure and improve the accuracy of fatigue analysis method. The method is exemplified by using more than 4000 NDT (Non Destructive Testing) inspection results in the period 1972 to 1995, including 600 platform years in the North Sea. Cracks were detected in 438 joints, while 181 joints have been found to contain propagating cracks ("fatigue cracks"). Each joint contains one or more cracks.
The observations of cracks are compared with theoretical predictions using a probabilistic fracture mechanics approach. The experience clearly demonstrates that the present tools for predicting fatigue crack growth give very uncertain but generally conservative estimates of the fatigue life. However, 1 to 3 percent of the components that have long fatigue life, have been observed to develop propagating cracks in a period, which is 20 years or less. For main structural and horizontal framing components the theory overpredicts the number of propagating cracks by a factor of approximately 3 while it predicts 70 to 80 percent of the propagating cracks observed.

Introduction
Fatigue is an important consideration for structures in areas with more or less continuous storms, such as in the North Sea, and especially for dynamically sensitive platforms. The gradual deterioration of strength due to crack growth makes it possible to apply design, inspection, maintenance and repair measures to ensure adequate safety. The first generation of jacket structures in the Norwegian part of the North Sea installed in the early seventies was not designed against fatigue failure. The degree of detail and quality of the analysis have been significantly improved since 1975. The methods of fatigue analysis referred to in this paper are typical for approaches used after 1990.1,2
There is a significant scatter in the different fatigue analysis approaches used during design and maintenance2. Differences in the methods, in particular where used to determine wave kinematics in the splash zone, hydrodynamic loads, deterministic vs. stochastic wave modelling, pile-soil flexibility, and SCF's as a function of geometry and load pattern, may cause a variability in fatigue life estimates of one to two orders of magnitude1. The inspection and maintenance engineers' reluctance to solemnly focus on fatigue life estimate as a basis for the long term planning work is not only based on this significant uncertainty, but also on observed conservatism.
Starting Right: Sable Offshore Energy Project's HFE Program
Authors: Robertson Neil L. 
Published: October 2008

Abstract
Human Factors Engineering (HFE) is the integration and application of scientific knowledge about people, facilities and management systems in order to improve their interaction in the workplace. The application of human factors contributes to the effectiveness of work systems by improving productivity and safety, and reducing the potential for human errors.
In other words, human factors is the systematic process of designing equipment, facilities, and the work environment for human use.
This paper focuses on the HFE program as developed for the Sable Offshore Energy Project (Sable). It details the various components of the program, the overall impact on the project and how the program was structured to support the multiple engineering, fabrication and construction locations throughout North America and Europe.
Consideration of HFE in front-end planning ensured that its philosophies were incorporated in all project phases. This allowed Sable to incorporate HFE in the base design, enhancing, economically, operational safety. HFE was involved in all aspects of the project, from conceptual design, vendor selection and detailed engineering, to construction and commissioning.
This paper documents the overall HFE program, from its initial introduction to venture management, to its integration in engineering, procurement and construction. Lessons learned from the Sable program will be presented.

Introduction
In May 1996, the proponents (owners) of the Sable Offshore Energy Project agreed to proceed with the front-end engineering design (FEED) of a new, large scale, onshore and offshore development. The Sable owners are:Imperial Oil LimitedMobil Oil Canada Properties (lead operator)Shell Canada Limited (joint operator)Nova Scotia Resources (Ventures) LimitedMosbacher Operation Ltd
The Sable project, located in the Nova Scotia offshore region, will provide up to 600 Mscfd of offshore gas production and onshore processing to access the estimated 3.0 TCF in Scotia Shelf reserves. Appendix A provides a detailed description of the project.
As the pioneer gas development in this area, Sable provided a relatively rare opportunity to incorporate HFE concepts into the base design and philosophy of a new operation. Gas production, processing and distribution infrastructure did not exist in Nova Scotia, and only conceptual designs for the project had been established. Therefore, the FEED teams had no area-specific design precedent to follow and looked to the project owners for direction.

Supportive Environment.
While the opportunity to implement HFE into the Sable design existed, it would have been very difficult to proceed without a supportive environment.
Drilling Well Control Practices and Equipment Considerations for Deepwater Operations Plans
Authors: Montgomery Michael E. , Leach Colin P. 
Published: October 2008

Abstract
Everyone recognizes the higher costs and technical challenges associated with drilling in deeper waters. As more information about operating in this frontier becomes known, planning and preparation can improve, reducing costs and risks. This paper will discuss well control issues associated with drilling. It will compare and contrast the requirements of the US MMS (Minerals Management Service), the UK and Australian Safety Case and Verification Schemes, and the Regulations and Guidelines of the NPD (Norwegian Petroleum Directorate). Of particular interest is hazard and risk analysis.
For effective risk analysis, one must first identify the magnitudes and type of events that may occur during a drilling or well control operation. Then, the operational capabilities and limitations of the equipment used to deal with such events can be explored to ensure they are fit for purpose. The net result is that not only can hazards be identified, but also their potential consequences estimated - the very essence of a good hazard analysis. As a result, the operator generates information that will improve the safety of his operation as well as his drilling effectiveness and (as a by-product) meet regulatory mandates.

Introduction
Every drilling program includes risk analyses, completed either explicitly or implicitly. As such, they are conducted for many reasons, including regulatory and prudent business practice. Although more comprehensive analyses undoubtedly reduce risk to a greater level, the expected fruit must be balanced against cost.
For the complete drilling process, assessing risks and consequences associated with well control and blowouts is a complex procedure. Fig. 1 (courtesy RF Rogaland) indicates some of the complexities of the procedures and the issues that must be addressed (1).
Fig. 1: Example of a comprehensive kick risk analysis (Available in full paper)
The results shown in the figure are in the form of probabilities of a kick occurring. The figure is included simply to indicate the scope of a complete analysis. No attempt is made in this paper to show how this complete analysis is carried out. It is only possible to quantify the risks and consequences if sufficient analysis is carried out to allow a process to be broken down into simple steps that then allows for a quantitative (or semi quantitative) assessment of failure on the part of an expert.
Installation of the Baldpate Compliant Tower
Authors: de Koeijer D. , Renkema D. , Edel J.C. , Willis C.H. , Payne D. 
Published: October 2008

Abstract
The Baldpate compliant tower, in Garden Banks block 260 in the Gulf of Mexico, is the first free standing, non-guyed compliant tower. Situated in 1,648 ft of water, it measures 1,900 ft. from the flare tip to the sea floor. The tower is a 19-slot drilling/production platform set over a 9-slot drilling template, has production facilities for 60,000 BOPD and 200 MMSCFD, and supports two steel catenary export risers. The tower was installed in the spring of 1998.
The tower has four basic structural components; the foundation piles, jacket base section (JBS), jacket tower section (JTS) and deck. Load-out weights for these were approximately 5,000 s. tons, 9,000 s. tons, 20,000 s. tons, and 4,000 s. tons respectively. This paper focuses on the installation of these components and also on the installation of the drilling template (Installed in 1994) and the docking and leveling piles (installed in 1996). Unusual aspects of the installation included the use of leveling piles instead of mud mats, deep lowering operation for the massive jacket base section; handling 530-feet long single-piece foundation piles and driving them with a single underwater hammer; launching of the jacket tower section from a launch barge that it exceeded in length by some 750 feet; and vertical mating of the two sections of the jacket at a depth of 1,300 feet.

Introduction
The Amerada Hess Baldpate compliant tower is located in the Gulf of Mexico in Garden Banks block 260 at a nominal water depth of 1648 feet. Particulars of the docking and leveling piles, the jacket base section, the skirt piles and the jacket tower section are;

Docking Piles (2 no.)
Dimensions : 84 inches O.D. × 206 feet Weight (dry) : 175 short tons (each)

Leveling Piles (4 no.)
Dimensions : 60 inches O.D. × 250 feet Weight (dry) : 125 s. tons (each)

Jacket Base Section (JBS)
Dimensions : 355 feet high, bottom 140 × 140 feet to leg centerlines, top 90 × 90 feet Weight (dry) : 9,000 s. tons

Foundation Piles (12. no)
Dimensions : 84 inches O.D., 531 feet Weight (dry) : 480 s. tons (each)

Jacket Tower Section (JTS)
Dimensions : 1410 feet high (including stabbing pins), bottom 90 × 90 feet, top 90 × 90 feet Weight (dry) : 20,000 s. tons
The contract for the transportation and installation of the platform components was awarded in February 1996 to HeereMac. Installation of the docking and leveling piles was completed in September 1996. Installation of the other platform components was completed in June 1998.
Numerical Prediction of VIV on Deepwater Risers Subjected to Shear Currents and Waves
Authors: Dalheim Joar 
Published: October 2008

Abstract
A numerical procedure to solve the coupled motion of a flexible riser and a viscous incompressible fluid is developed. In this study, the former is solved by a multi-modal response model and the latter is solved by a sectional solution (strip theory) method. In every fluid section the 2D-vorticity equation is solved by a Vortex-in-Cell method and the different fluid sections are coupled through the boundary conditions from the motion of the riser. This procedure is used to solve the vortex-induced vibration (VIV) response of flexible risers. Both vertical risers and steel catenary risers are predicted by the present method. The method can also be used to solve the coupled motion of two or more flexible risers. A fatigue analysis module is included in the numerical package. The present method is validated against experimental tests and other numerical tests, and the riser response and fatigue life is found to be in good agreement. The numerical results are visualized to obtain better understanding of the computed results and the phenomenon.

Introduction
As the oil industry is moving into deeper and deeper waters, the structures are becoming more and more slender and hence prone to vortex induced vibrations and large displacements. When one or more risers are exposed to a sheared current there will almost always be induced some kind of vortex-induced vibration. In order to be able to predict the fatigue damage caused by these transverse vibrations it is crucial to know which modes that will dominate the response of the risers and at what amplitudes they are responding. In addition, if more than one riser is analyzed, it is important to be able to predict the coupled response of the riser system. And numerical tools with this feature included will be of great support to the oil industry. In order to help the engineer to understand the motion of long and flexible cylinders (e.g. risers and anchoring cables) in fluid flow, a computer program with the capability of visualizing these motions is developed. A modal analysis is used to predict the cylinder motion, and the fluid domain is solved by the vortex in cell method. General physical equations are utilized in order to make an effort of making the computer program general and being able to solve a number of different classes of VIV problems (such as collision of multiple risers, steel catenary risers, deepwater risers, surface waves, etc.).
The remainder of this paper can be outlined as follows: the next section describes the fluid solution procedure, then the structural response prediction is reviewed, and then the fluidstructure interaction procedure is discussed. This is followed by some numerical results and some concluding remarks.

The Fluid Solver
The fluid domain is modeled by a so-called strip theory in which the fluid is divided into 2D sections (Fig. 1) along the span of the riser. On each of these sections the fluid flow is found by solving the vorticity equation.
Highly Compliant Rigid (HCR) Riser Model Tests and Analysis
Authors: Grant Robert G. , Litton Richard W. , Mamidipudi Partha 
Published: October 2008

Abstract
A 1998 Joint Industry Project performed large-scale model tests and analysis of three Highly Compliant Rigid (HCR) riser configurations. The tests were conducted in about 800 ft of water. The objective was to reduce operator cost and risk by improving and verifying riser analysis methods. This was accomplished by a 3 step sequence of pre-test analysis, physical model tests and comparison of analysis with test results. The pre-test analyses were performed by 13 independent organizations using 11 riser analysis computer programs. The subsequent model test results were used to improve and verify the analysis procedures. The model tests taught many lessons including the importance of the seafloor soil and intermittent vortex induced vibration (VIV) to the overall riser response. Riser analysis programs available today have very limited capability to model the soils, and are unable to model intermittent VIV.

Introduction
The cash flow from industry's future "billion dollar" deepwater field developments will depend on risers. In very deep water, complex steel/polymer flexible risers ("flex risers") may not be technically or economically feasible, especially in larger diameters, because of their relatively high weight and cost. A reliable alternative would be attractive.
"Flex risers" are typically specified because of their capability to bend in response to floating platform wave motions without incurring excessive fatigue damage. Their bending flexibility also simplifies installation. However, in deep water where vessel motions are a relatively small fraction of water depth, simple rigid pipe can be configured into overall shapes that provide the compliance needed to absorb platform motions. Their key design basis parameters are diameter, internal/external pressure, water depth, platform motion characteristics (e. g., ship, spar, semisubmersible, TLP) and wave environment.
HCR risers have clear benefits over "flex risers" but present new design and analysis challenges. One of these challenges derives from the cyclic tension introduced by platform heave motions which makes bending stiffness highly variable and makes the problem highly non-linear. The cyclic tension can produce short periods of compression and negative bending stiffness that causes difficulty for some solution schemes. While there are several riser analysis programs available to the industry that address these computational requirements, there is little model or full-scale test data available for their validation.
A key objective was to determine if the buckling predicted by some analysis programs is an artifact of the modeling or if it really occurs. If it does occur, then it was an objective to assess the accuracy of programs in predicting the onset of buckling. Another objective was to determine the magnitude of the effect of sea floor soils on riser response.