bluuebunny/crossref_metadata_2025_split huggingface dataset:
SS: FPSOs and Floating Production Systems: The Monitas system for the Glas Dowr FPSO
Authors: Aalberts Pieter , van der Cammen Jeroen , Kaminski Miroslaw Leck 
Published: July 2010

ABSTRACT
The paper is one of five papers about the Advisory Monitoring System (AMS) for controlling the fatigue lifetime consumption of FPSO hulls. The system has been developed within the Monitas Joint Industry Project (JIP) and is referred to as the Monitas system. The name Monitas stands for Monitoring Advisory System. The paper describes the Monitas system developed, installed and running for two years on-board the Glas Dowr FPSO operated by Bluewater Energy Services (BES) at the Sable field, offshore South Africa. The paper describes how the Monitas system advises on fatigue lifetime consumption based on the fatigue design data, fatigue design tool and the monitoring data of hull girder loads, global and local stresses, wave frequency motions, ship's loading condition and heading, and the environmental conditions. The paper concludes that contrary to conventional structural health monitoring systems, estimating the actual fatigue lifetime consumption, the Monitas system can explain potential deviations from the design assumptions. In this way the Monitas system provides designers with feedback about the quality of their design tools and made assumptions, and advises the FPSO operators on actions required to ensure a safe operation and, if needed, can be used to justify lifetime extension.

Introduction
Hull fatigue of FPSOs is an important design consideration which has been addressed in several Joint Industry Projects (JIPs) in the last two decades. In the late 90s, hull fatigue was investigated in the FPSO Integrity and FPSO Capacity JIPs. The FPSO Integrity I and II JIPs were headed by MARIN and their aim was to investigate the fatigue loading on an FPSO hull. For this purpose, BES's FPSO Glas Dowr (see Figure 1), at that time located at the Durward & Dauntless field at the UKCS, was instrumented with an extensive measurement system to collect data on hull loading. An extensive overview of this JIP and the monitoring system are given by Bultema (2000) and Boom van den (2000). The FPSO Capacity I and II JIPs were led by DNV and their main aim was to investigate and develop methodologies to describe the fatigue capacity of typical FPSO structural hull members. An extensive overview of these JIPs can be found in Lotsberg (2000). Although a lot of knowledge was acquired in these JIPs, additional development was needed in the FPSO Live JIP, which was led by BES in cooperation with MARIN and DNV. This JIP developed a hull fatigue calculation procedure in the time-domain and investigated a minimum monitoring system, i.e. the minimum amount of sensors required to derive fatigue loads on the hull of an FPSO.
SS: Perdido Development Project: Great White WM12 Reservoir and Silvertip M. Frio Field Development Plans and Comparison of Recent Well Results with Pre-Drill Models
Authors: Eikrem Vern , Li Ruijian , Medeiros Michael , McKee Bryce J. , Boswell Betsy Lorene , Shumilak Edward E. , Mohan Raj 
Published: July 2010

Abstract
The Great White and Silvertip Fields are located in the southern Alaminos Canyon area of the far western Gulf of Mexico. Shell is the operator of the Great White and Silvertip Fields. Along with Shell, Chevron and BP are the Great White JV partners. Chevron and Shell are JV partners in the Silvertip Field.
This paper will provide an overview of the current Great White Field WM12 reservoir development plan, will compare the results of the recent six development wells with the pre-drill predictive model, and the impact of the well results on our understanding of this frontier area, Paleogene age reservoir. In addition, excellent results in two horizontal wells drilled in the Silvertip Field shallow M. Frio reservoir are also highlighted along with the well construction challenges in drilling and completing them.
Oil in the Great White Field WM12 Sand reservoir is trapped in a large, highly faulted anticlinal structure. A high-resolution 3D seismic survey shot over the field has enabled us to map this structurally complex field reservoir in detail, identify hundreds of faults, and estimate reservoir thickness and quality away from sparse exploration and appraisal well control.
The Great White JV partnership plans a staged development of the WM12 Sand reservoir. Staged development of this frontier area, ultra-deepwater field mitigates the downside production risk associated with Great White's structural uncertainty, the scarcity of well data, the lack of reservoir production data, and the potential for reservoir compartmentalization due to sub-seismic faulting and / or stratigraphic barriers to flow.
Development drilling at Great White began in 2007 and to-date six pre-drill wells have been drilled and completed prior to first oil. Well results drilled prior to first oil at the Perdido Spar and at the subsea Southwest Cluster locations are in-line with our pre-drill expectations and so far, have confirmed our large estimated oil-in-place volume in the WM12 Sand reservoir in the field.
The M. Frio oil reservoirs at Silvertip Field are located in shallow M. Frio canyon-fill sands. The M. Frio is relatively unconsolidated and contains high viscosity, heavy oil. Because the M. Frio reservoirs are relatively shallow, drilling margins are very low and the wells push the boundaries of extended reach drilling. With detailed planning, we have been successful in drilling and completing these long horizontal wells and had better than expected well results.
Directional Casing While Drilling (DCwD) Heralds a Step Change in Drilling Efficiency from a Producing Platform
Authors: Dawson Graeme , Buchan Andrew , Kardani Ilen , Harris Andrew , Wercholuk Lonnie , Khazali Khairul Amir , Sisson Keith , Halim Abdul , Hermawan Heru 
Published: July 2010

Abstract
Directional casing while drilling (DCWD) utilizing a rotary steerable system or a steerable positive displacement motor is a recent enabling technological application of proven casing while drilling. DCWD has been successfully applied in wells in the North Sea and Middle East using both rotary steerable systems and PDMs, proving up its operational reliability. The technology has most recently been utilized in a project from a producing platform in the Asia Pacific region. While this DCWD application increases the challenges of directional drilling, the project was completed successfully in terms of increasing ROP and lowering the time and cost to drill the top hole section of the well.
Top hole directional drilling of wells in high density locations such as multi-well producing platforms require carefully planned, detailed procedures and reliable techniques to result in a safe and efficiently drilled wellbore. The procedure, in addition to directional capabilities, requires that the well meet the demands of anti-collision concerns within the torque and hydraulic operating parameters of the formation. The drive for continuous improvements led the field operator to choose DCWD technology to deliver step changes in drilling performance while meeting the company's strict operational and safety directives.
The successful effort was a carefully planned and implemented operation that required the close cooperation of the operator, directional drilling company and drilling contractor during the entire procedure. This close interaction between all parties led to three world records and the world's first application of another enabling technology, including:World's deepest 13 3/8?? DCWD job;World's highest angle directional well with 13 3/8?? DCWD;World's fastest rate of penetration for a 13 3/8?? DCWD;World's first application of Gyro MWD with DCWD.
SS: Perdido Development Project: World
Authors: Snyder Dale , Townsley Bill 
Published: July 2010

Abstract
The Perdido Development Project is an ultra-deep water development of the Great White, Silver Tip and Tobago fields in the remote southwestern Gulf of Mexico (Figure 1). Perdido will be the first to produce from the Lower Tertiary (Paleogene) geologic setting in the Gulf. Moored in 7817 feet (2,382m) of water in Alaminos Canyon Block 857, the spar host will be the world's deepest drilling and production facility. In 9627 feet (2,934m) of water, the Tobago subsea oil well will be the deepest producing well in the world. This paper will provide an overview of the Perdido project, discussing the challenges that had to be overcome and the innovations that had to be developed to successfully deliver the project.
Perdido Development facilities (Figure 2) consist of:Truss spar with light weight, " single-lift?? topsidesSix-slot, wet-tree, direct vertical access (DVA) well system with a full capability drilling rig34 subsea wells including the 22 DVA wells under the sparAll production commingled on the seafloor, gas separated from liquids and liquids pumped from the seafloor up to the spar hostThroughput: oil 100 mbopd, gas 200 mmscfd, water 40 mbwpd, water injection 80 mbwpdOil and gas export pipelines
The significant challenges to delivering Perdido fell into the categories of safety, the need for new technology and low cost solutions, and overcoming overheated market conditions. With all of the many difficulties to be overcome, the team committed itself early in the project to intensely focus on safety as the highest priority. The result has been both outstanding project execution safety performance across many locations and in the raising of the bar of how safety is incorporated into platform designs. As to the technical and cost challenges, Perdido's difficult reservoirs, high well count and ultra-deep water made the development uneconomic with conventional deepwater technologies. To produce the wells, reduce the size of the host and reduce the cost of development, an innovative system of new technologies was required, consisting primarily of wettree, direct vertical access (DVA) wells with a Subsea Boosting System. Sanctioning and executing the project during one of the industry's most overheated markets created numerous cost, quality, resourcing and delivery problems, requiring extraordinary effort from the project team and contractors to keep the project on track.
SS: Perdido Development Project: Surveillance & Operations Technology
Authors: Purdy Gill E. , Littell Howard Steven , Lajeunesse Susan , Coulon Todd , Durham Kevin , Lee Amanda 
Published: July 2010

Abstract

- Description
Operating in the ultra deep-water environment at Perdido (7800-9200 ft) makes Surveillance readiness essential on this complex, technologically challenging asset. Early work on integrated production system modeling, an operations training simulator, ESP surveillance tools, collaborative work environments, remote accessibility, and real time interactive process data trending have enabled an accelerated learning pace for Perdido. This paper will communicate the efforts required to successfully meet this ultra deepwater challenge during the early field development and startup. This work has been completed by Shell on behalf of the Perdido joint venture partners Chevron & BP.

- Application
Surveillance & Operational technologies developed for this deepwater environment will allow for the smooth startup of the Perdido Field and for the collection of critical reservoir data needed for further field development. This technology can be applied to other deepwater fields to optimize field startup while gathering critical early surveillance data and minimizing the number of personnel required on location.
A process simulator was used to simulate field operations and to interface with the actual control system. It synthesized realistic responses to Operator inputs for training & scenario trouble shooting purposes.

- Results, Observations and Conclusions
Due to the Operational challenges at Perdido, staffing for an Operational Readiness team was started 4 years prior to first oil. This team has grown over the years and was fully staffed around 6 months before startup. Their job was to develop the operating procedures & manuals for Perdido, and then train the team how to start up & operate the field. Similarly, staffing for the Engineering Surveillance team began 24 months before first oil and was completed 12 months before startup. The team's job was to build the systems, procedures, & collaborative processes that would be required for a smooth startup & surveillance of Perdido. All these technologies & detailed planning should result in the smooth & flawless startup of Shell's first Spar platform in the ultra deepwater.

- Significance of Subject Matter
Ensuring that Operations personnel are properly trained to operate the field is imperative for a smooth startup of Perdido. In addition, proper preplanning & training will be critical for startup & ramp up of the Perdido field.
Deepwater Mooring Systems - Advances in Connector Technology and Implementation Practice
Authors: Green Brian 
Published: July 2010

Abstract
The time has come for dedicated deepwater mooring systems that accurately reflect the practical and technological demands of deploying mooring systems beyond 10,000ft (3,000m). This paper describes how new developments in mooring connector design and polyester ropes will provide operators with dedicated deepwater mooring systems.
Installing long-term, deepwater moorings for spars, floating production units, FPSOs and their associated Submerged Turret Production (STP) / Submerged Turret Loading (STL) Buoys is proving to be increasingly time-consuming and costly, as mooring equipment and practices developed for shallow water are applied to deepwater environments.
The paper will review the elements of deepwater mooring with particular reference to the integrity of deepwater mooring connectors and the excessive complexity of mooring line interconnectivity, resulting in increased installation times and vessel costs. In addition, it will report on developments in mooring line and connector technology that are designed to improve the engineering integrity of rope connectors and the application of ‘lean installation’ practices to deepwater mooring line deployment.

Introduction
There is a need for dedicated deepwater mooring systems that accurately reflect the practical and technological demands of deploying mooring systems beyond 10,000ft (3,000m). Deepwater is defined as water depths greater than 1,000ft (305m), and ultra-deep water is water depths greater than 5,000ft (1,524m).
Recent deepwater mooring projects such as SBM Atlantia's Thunder Hawk Floating Production Unit (FPU) moored in 6,050ft (1,800m) of water (Fig. 1), and Shell's Perdido Truss Spar Development project in the Gulf of Mexico, moored at a depth of 8,637ft (2,632m) are part of the growing trend in deepwater and ultra deepwater production in the Gulf of Mexico (GoM). In 2010 the first deepwater FPSO in the GoM will be deployed in the Cascade-Chinook fields, with a submerged turret production buoy moored in 2,500m of water.
As moorings go deeper, so issues surrounding the mechanical and practical demands on the design and deployment of mooring systems are coming to the fore. Installing long-term, deepwater moorings is proving to be increasingly time-consuming and costly, as mooring equipment and deployment practices developed for shallow water are applied to more demanding deepwater environments.

Deepwater Exploration, Development and Processing
The trend towards deepwater exploration and processing is gaining momentum, in the search for new oil and gas fields. The US Department of Interior's Minerals Management Service (MMS) believes there is more than 50 billion recoverable BOE still to be discovered in both GoM deepwater and ultra-deepwater regions.
Revisiting the Subsalt Trap Archetype Classification Scheme After Eight More Years of Gulf of Mexico Subsalt Drilling
Authors: Hart Bill , Albertin Martin L. 
Published: July 2010

Abstract
Subsalt exploration in the Gulf of Mexico (GOM) remains an area of intense focus by the oil and gas industry. Successfully accessing economic hydrocarbon accumulations beneath the extensive allochthonous salt sheets in the northern GOM basin requires solving a number of geophysical, geological, and drilling challenges. In 2001, Hart and Albertin presented a geological tool which, given imaging challenges associated with complex allochthonous salt, could be used for qualitatively ranking subsalt exploration prospects according to their structural attributes.
The ranking scheme proposed by Hart and Albertin is comprised of a collection of subsalt trap archetypes, each archetype representing an important structural variation with specific trap merits and risks. These archetypes are grouped into four genetic play families, calibrated for overall prospectivity by a statistical analysis of subsalt well success rate. The statistical analysis in 2001 used a database of 69 subsalt wells; since then, at least 122 new subsalt traps have been drilled by the industry. We used this new subsalt well data to revisit the classification scheme and answer a few specific questions: does the trap family priority hold up given the subsalt successes and failures of the past eight years, do the original archetypes still represent the full range of observed salt styles, and are any revisions to the classification scheme warranted?
At a high level, the subsalt trap family prioritization still holds. All but two of the 45 new subsalt discoveries can be positively attributed to the top ranked autochthon-rooted trap family. With only two possible exceptions, where root style could not be determined, none of the other subsalt trap families yielded a single discovery in the past eight years. Further analysis of the 107 new autochthon-rooted subsalt tests suggests the following descriptive and statistical updates to the autochthon-rooted trap family:the overall success rate of autochthon-rooted traps, which currently stands at 42%, has been favorably impacted by the emergence of the Paleogene (Wilcox) play trend,the trap family has been broadened to include cases where traps form above deep Cretaceous salt allochthons, and above Louann salt that has crept onto younger oceanic basement,northward and westward expansion of the deepwater subsalt play fairway necessitates the addition of new end-member archetypes within the autochthon-rooted family,the industry will be challenged to maintain the high success rate for the autochthon-rooted trap family as subsalt exploration focus within the GOM shifts from the lower slope to more complex subsalt traps of the middle to upper slope.
Flexible Pipe Integrity Monitoring: A New System to Assess the Flexible Pipe Annulus Condition
Authors: Dion Dominique H. , Murray Nuala Mary , Roques Jean-Philippe , Balague Benoit , Audouin Gregoire 
Published: July 2010

Abstract
One of the main concerns regarding flexible pipe integrity is its annulus condition, as a flooded annulus can lead to excessive corrosion and reduce fatigue life of the armor layers. The current approach to address this is to periodically perform a vacuum or pressure test to check the annulus integrity and to measure its gas-filled volume, in order to detect an accumulation of condensation water, or the ingress of sea water (Bondevik, 2004). These measurements are sometimes complemented by a continuous measurement of the flow rate of gas escaping the flexible riser's vent ports (MCS International, October 2002). The vacuum or pressure test is a costly operation, performed intermittently, while the conventional vent-gas monitoring does not provide reliable information on gas diffusion rates or water vapor emissions.
To address these issues, TOTAL and Schlumberger have developed the subC-racs* riser annulus condition surveillance system for continuous monitoring of flexible riser integrity, which eliminates the need for vacuum tests.
The gas that permeates the riser pressure sheath is depressurized while measuring its pressure, temperature, and flow rate. As in a well production test, the pressure drawdown and buildup curves are analyzed to give detailed information about fluid content and connectivity. The instrument's resolution and accuracy allow frequent calculations of gas diffusion rate and of the volume of liquid that may have entered the annulus, weekly, daily, or more frequently, depending on gas diffusion rate and riser parameters.
In this paper we describe the measurement principle and hardware, modeling of the gas diffusion in the annulus compared with experimental results, and field test results on various risers in a West Africa field. Emphasis is placed on the measurement results, but the implementation in hardware and real-time software for alarms and remote monitoring is also shown.

Introduction
Monitoring of flexible pipe integrity is a main concern for all offshore fields. It has become more significant as the number of flexible risers increases, and as they age.
The main issues for flexible risers are the status of outer sheath and the presence of water in the annulus due either to condensation or by damage to the outer sheath (Figure 1).
Understanding SMS Behavior to Define the Subsea Mining Operating System
Authors: Espinasse Philippe 
Published: July 2010

ABSTRACT
Seafloor deposits are a very promising source of mineral ore for the near future, discovered over the last 40 years. In particular, Seafloor Massive Sulphides (SMS) are very high grade hydrothermal mineral deposits distributed on the mid ocean ridges, arc and back arc basins in the deep confines of the world oceans. The most commercially attractive minerals are copper and gold, combined with large quantities of lead, zinc and silver. The first deposits that will be developed are located in 1600 to 2000 m water depth. Production will start on a commercial level by 2011.
Applicable cutting and lifting technologies must be defined and tested rapidly so that the full production system can be engineered and built in a very short time frame. Existing oil and gas deep water developments is a proven source of technology that can be used as the basis of knowledge and experience to meet this challenging schedule.
As a company at the forefront of deepwater developments, Technip is deeply committed to this new industry. A strong and comprehensive R&D effort has been put together to characterize the ore, its behaviour under load, its effect on the lift system and all related flow behaviour within the riser system.
The R&D effort is split in four topics, all closely inter-related:Rock characterization performed in cooperation with Ifremer which has made available its SMS samples gathered over 30 years of deepsea exploration campaigns to determine mechanical and chemical behaviour of the SMS.Crushing test in hyperbaric conditions to evaluate the effect of pressure on cutting forces and determine rock size distribution.Slurry transportation models were performed using state of the art CFD modelling, both in two-phase and three-phase flow. This will be confirmed through large scale test loop experiments.Abrasion tests have been performed to select the preferred liner material for jumpers and risers. These liners will be tested in the test loop to confirm their behaviour over time.
This paper describes the test program, provides the main available results and identifies the way forward to meet this technological challenge.

INTRODUCTION
Seabed Massive Sulphides are the subsea equivalent of Volcanic Massive Sulphides which have been exploited on land over the years. These hydrothermal mineral deposits are very high grade ore accumulations present on the seabed, located on the back arc basins and mid ocean ridges. Of particular interest are those located on the Pacific rim of fire, within the exclusive economic zones of various countries, in water depths of less than 2500m.