bluuebunny/crossref_metadata_2025_split huggingface dataset:
CUBE - A New Technology for the Containment of Subsea Blowouts
Authors: Andreussi H.P. , De Ghetto G. 
Published: February 2015

Young Technology Showcase
After the Macondo incident, the oil industry started a significant review of its capabilities to respond to a subsea well blowout and launched some specific development projects. Eni decided to participate in the principal joint industry projects launched on this topic, and also started internal activities aimed at the development of new containment methods.
Two years after Macondo, it is clear that the major containment method of a subsea blowout relies on the use of a capping stack. This can be deployed in water depths as deep as 3000 m and equipped with multiple outlets that allow liquid and gaseous hydrocarbons to be routed to surface.
However, in some cases well capping cannot be applied when a) well-integrity issues arise, this may happen when the capping stack causes a substantial pressure increase at the wellhead, with a potential rupture of the casing and the lateral dispersion of well fluids; b) the blowout preventer (BOP) stack is not accessible because of mechanical problems (status of wellhead/BOP or irremovable debris); c) the blowout does not come directly from the well (i.e., from nearby sea lines or mud line). On the basis of these and similar considerations, it is quite clear that the containment of a blowout event cannot only rely upon the use of a capping stack and other methods must be available.
Eni has been working in the last 2 years on a new concept with the support of TEASistemi, a research company of the University of Pisa, developing an alternative to the capping technology. This system is based on the use of an open-sea containment system, which is able to perform at least partial gas/liquid separation. After separation, most of the liquid hydrocarbons plus a minor amount of seawater are pumped to surface. The gas phase can be sent to surface through a separate riser or can be discharged at sea. In order to prevent hydrate formation within the separation system, there must be a low separator-residence time. The system conceived by the authors of this paper has been patented in June 2010 (De Ghetto and Andreussi, 2010) and the first tests were performed in September 2010 at the TEASistemi Laboratory in Pisa.
Of course the concept of subsea phase separation is not new for the oil industry, but up to now it has not been adopted for the containment of subsea blowouts. The reason probably being that up to the Macondo incident, it was believed that subsea collection and transmission to surface of blowout fluids could be easily accomplished by some type of containment dome. Unfortunately, the Macondo incident showed that this is not always the case and that the use of a containment dome presents a number of potential problems which need to be faced, such as the formation of hydrates, the poor control of the system, and finally, issues associated with large fluxes of seawater into the dome.
Case Studies Examine Exploitation Strategies for Development of Mature Gas and Oil Fields
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23373, ’Exploitation Strategy in the Development of Mature Gas and Oil Fields: Case Study,’ by Gina Vega Riveros, Reservoir Consultant, and Emad Yehya, Smoothwell Oil Services, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. Copyright 2012 Offshore Technology Conference. Reproduced by permission.
Two case studies examine the creation of strategies for the development of mature gas/condensate and oil fields. For the gas/condensate field, the integration of geologic, seismic, production, and reservoir data identified new opportunities for drilling. For the oilfield case study, it is clear that the strategy of exploitation can be improved. According to study results, the oil and gas condensate in place have been increased by 9% and 22%, respectively, compared with the official reserves estimates.
Gas/Condensate Case Study
Geologic Framework. The gas/condensate reservoirs are in the Roble, San Joaquin, and Guario fields, approximately 11 km southwest of Anaco, Venezuela. The geological model in the Guario 3 reservoir allowed for the integration of four reservoirs as a unique hydraulic unit (Fig. 1). Geologically, the study area is within the greater Oficina area, on the south flank of the Eastern Venezuela basin.
The Merecure formation is Oligocene to early Miocene and was deposited in a transitional environment, yielding sandstones with good lateral extension.
Petrophysics. In Guario 3, ME-G and ME-H sands have an average effective porosity of 14%. Permeability ranges from 20 md to more than 70 md. The water resistivity of 0.1 Ω·m, cementation exponent of 2.00, saturation exponent of 2.00, and shale volume cutoff of 40% were obtained from field data. Both ME-G and ME-H sands showed similar petrophysical properties.
Reservoir Properties. The northwest-ern crest of the Guario 3 reservoir is defined as gas/condensate crude. The eastern part contains a volatile zone of medium gravity with a high concentration of paraffin. The integrated static and dynamic models validated the existence of an areal and vertical communication of four reservoirs into a unique reservoir named Guario 3 (G-3).
Geochemical Study. To verify vertical and lateral reservoir communication between ME-G and ME-H sands, gas chromatographic correlations of samples from wells in different reservoirs were used to establish a clear vision about fluid communication.
Correlations for Predicting Gas/ Condensate Reservoirs. Many empirical correlations have been reviewed in the literature, and they take into account retrograde condensate. The average ranges for applying the correlations and the equations used can be found in the complete paper. Using the correlations, the original gas condensate in place was 1226.84 billion scf, which was considered satisfactory in comparison with the volumetric method of 1267.37 billion scf.
Reducing Uncertainty to Ensure Future Asset Performance
Authors: Ketelaars Frank 
Published: February 2015

Guest editorial
Over the past 5 to 10 years, there has been an increasing focus in the offshore oil and gas industry on predicting and quantifying an asset’s expected production performance. This “performance risk” has always been considered one of the key risk factors for an offshore development, in addition to subsurface, economic, safety, and environmental risks. However, with the shift of offshore developments to harsher environments and deeper water, the traditional method of estimating expected availability and production performance figures, using extrapolated data from previous experience, is increasingly considered insufficient.
With increased investment required for some of the ambitious new offshore developments (floating liquefied natural gas [FLNG], Arctic, and ultradeep developments), there is growing pressure to address any risk to the bottom line and understand how the impact of changing environments and operating conditions will affect economic return and expected revenue. As a result, most operators are now adopting more robust methodologies, such as using simulation technology tools, to evaluate and predict expected performance.
Several key areas in the offshore industry illustrate where these “new” production risk factors are especially relevant.
The subsea industry, in particular, continues to undergo rapid transformation as it seeks to exploit untapped reserves. Subsea fields exploited since the late 1990s in the North Sea, US Gulf of Mexico (GOM), and offshore Brazil are now considered areas using proven technology and their performance is well understood. However, pushing subsea developments into ultradeep locations does result in additional performance risk. The 2010 Macondo accident in the GOM clearly showed that the potential impact and escalation of subsea failures or incidents can be dramatically increased because of high water depths. The ultradeep environment will affect potential diagnostics options (Is there a leak? Where is it coming from?), and mitigation and repair options (What intervention activities are possible? Which vessels are available at short notice?). A relatively minor failure, which could have been addressed quickly by divers or remotely operated vehicles in shallower waters, can potentially result in long well or even field outages. In addition, public scrutiny concerning any potential environmental impact would make it likely that operators would now opt for conservative decisions (e.g., a shutdown) in the event of any uncertainty about potential subsea leaks or failures.
Overcoming the Oil and Gas Talent Void By Focusing on the Core Business
Authors: Swanson Charles 
Published: February 2015

Playing to its core strengths is generally a sound strategy for any company, in any industry. But it is especially important now for oil and gas companies, when technical and scientific talent in the oil patch is so hard to come by. The oil and gas work force has been declining steadily for almost 20 years. During that time, many companies that should have been competing vigorously for the dwindling resource of human capital instead found themselves staffing up in noncore functions.

Supply and Demand Leads to…Bust?
Other industries have had their slumps, but the bust that hit the oil and gas industry in 1986 was unusually severe and has left long-lasting marks. When commodity prices collapsed, technical, professional, and field workers were forced to leave the industry by the hundreds of thousands. Hundreds of companies disappeared, and in many cases they were acquired by larger competitors. The most striking way in which the oil and gas slump of 1986 was quite different from that which affected other industries is that when the recovery came, workers who had been forced to leave did not return. More alarmingly, they were not replaced with new talent either.
The reasons were numerous. Chief among them was the intensely cyclical nature of the industry and the depth of the downside. People were no longer willing to weather the cyclical nature of oil prices. Also responsible were the explosion of information technology, the advent of the Internet, and the subsequent boom in high-tech, high-paying jobs in this hot new industry. The best and brightest technical and professional workers now had more options than ever before.
Of course, one also needs to be honest about the image problem. Negative portrayals of the oil and gas industry in the media and political circles undoubtedly caused many qualified young workers to take their talents elsewhere. According to the U.S. Bureau of Labor Statistics, there were approximately 33,000 petroleum engineers in the United States in 1983. By 2002, that number had dropped 45% to 18,000. The numbers for geologists and geophysicists are similar—from 65,000 in 1983 to 48,000 in 2002, a drop of 26%. Conversely, the number of computer systems analysts exploded from 276,000 in 1983 to 1.7 million in 2002—a growth of 531%.
While young people were choosing different career paths, the oil and gas workers who entered the work force in the 1960s and 1970s—and survived the 1980s—continued to shepherd the industry through turbulent times. They are now either retired or nearing retirement age, leaving the industry with a serious lack of manpower.
Continuous Borehole-Curvature Estimates Based on Downhole Bending-Moment Measurements
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90794, "Continuous Borehole-Curvature Estimates While Drilling Based on Downhole Bending-Moment Measurements," by G. Heisig, SPE, Baker Hughes Inteq; G. Cavallaro, Eni SpA Div. E&P; and P. Jogi, SPE, J. Hood, SPE, and I. Forstner, SPE, Baker Hughes Inteq, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
A downhole bending-moment measurement combined with a simple mathematical model can provide a good estimate of well-bore curvature, matching results obtained from survey-data analysis well. The bending-moment measurement delivers well-bore-curvature information at a much higher resolution than the standard minimum-curvature method that assumes a constant curvature between survey stations.

Introduction
Any drilling bottomhole assembly (BHA) in a directional wellbore is subjected to bending moments caused by side forces acting on the BHA. These side forces may be caused by gravity, by dynamic effects, or by wall contacts of the BHA in curved wellbore sections. Mathematical models have been developed to predict the side forces, bending moments, and stresses that are introduced into a BHA by a given borehole-curvature profile, usually derived from measured survey data.
The full-length paper discusses application of mathematical models to predict the borehole curvature from measured bending-moment data. The bending-moment data were acquired with a recently introduced drilling-dynamics tool in a variety of different applications and tool configurations including rotary-steerable systems (RSSs) and steerable-motor BHAs. The bending-moment data can be both transmitted to the surface while drilling and recorded in on-board memory for post-run processing and detailed analysis.
Expandable-Metal Technology Creates a Monobore Well
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16670, "Using Expandable-Metal Technology To Create a Monobore Well," by Matthew Jabs, SPE, Baker OIl Tools, originally prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
The introduction of expandable-metal technology into the oil and gas industry in recent years has allowed a change in traditional well-construction design. The advent of this technology is allowing operators to drill wellbores that do not subscribe to the traditional telescoping reduction in casing sizes as well depth increases. This capability allows deep wells to be drilled without sacrificing well hole size, which has many advantages, ranging from lower wellbore construction costs to greater production potential. The full-length paper outlines a method of creating a monobore well over a finite length of well path.

Introduction
The primary benefit of a monobore well is the ability to reach the desired drilling depth without sacrificing casing size. This capability can allow much deeper or deviated wells to be drilled because of the elimination of the hole-size reduction. Should an unexpected hole problem be encountered while drilling, a monobore-well design provides the ability to set a section of casing across a problem zone and continue wellbore construction without sacrificing hole size. By developing wells from the surface to total depth using a monobore design, it is possible to reduce surface-equipment size. Use of smaller-sized equipment and casing may translate to direct cost savings.
Hydrodynamic Aspects of Gravity- Based Structures in Shallow Water
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16716, "Hydrodynamic Aspects of Gravity-Based Structures in Shallow Water," by B. Buchner and G.E. Loots, Maritime Research Inst., The Netherlands, and G.Z. Forristall and E.J. van Iperen, Shell Intl. E&P, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Concrete gravity-based structures (GBSs) are being studied for shallow-water oil and gas developments. Three subjects must be considered: wave amplification with respect to deck elevations, the hydrodynamics of liquefied-natural-gas (LNG) carriers moored to GBSs, and wave run-up and possible green water on the deck of the GBS.

Introduction
A concrete GBS for offshore oil production usually consists of a base caisson supporting several vertical columns, which in turn support a deck containing production facilities. Some of the first were built for deepwater fields in the Norwegian sector of the North Sea. The Troll platform in 303 m water depth remains the tallest object moved over the face of the Earth. Soils in the Norwegian sector were strong enough to support the massive structures, and their mass is sufficient to resist the overturning forces caused by environmental loads. Because the base of a GBS is large, it is easily adapted for oil storage. Production can be stored until a load large enough to fill a tanker is accumulated.
Malampaya is a good example of GBS use in shallow water. The Malampaya gas field is in water approximately 820 m deep, but the production is sent by pipeline from the subsea wells to the GBS in 43 m water depth, where it is processed. The dry gas is sent to power plants in the Philippines, and the condensate is stored in the base of the GBS for eventual shipping by tanker.
Two GBSs are planned for the Sakhalin II project in the Sea of Okhotsk. In this case, another advantage of this type of structure is exploited: they are able to resist forces from seasonal ice cover and ice movement.
Recently, several companies began investigating the possibility of building a GBS as an offshore terminal for importing LNG, as shown in Fig. 1. The structures likely will be rectangular caissons, which also will serve as breakwaters for the LNG tankers. They also will store the LNG and support the regasification equipment.
In-Situ Characterization of Formation-Fluid Samples - Case Studies
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90932, "In-Situ Characterization of Formation-Fluid Samples - Case Studies," by H. Elshahawi, SPE, and M. Hashem, Shell Intl. E&P Inc., and C. Dong, SPE, P. Hegeman, SPE, O.C. Mullins, SPE, G. Fujisawa, SPE, and S. Betancourt, SPE, Schlumberger Oilfield Services, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Fluid sampling in the early stages of exploration and development provides key information for field planning and facilities design. In many deepwater and other high-cost wells, formation-tester samples may be the only reliable source of fluid properties for economic screening. Real-time in-situ fluid characterization can ensure sample quality and optimize the sampling process. Techniques for downhole fluid characterization include real-time composition measurement, fluid-type identification, and single-phase assurance.

Introduction
To develop deepwater prospects and other capital-intensive E&P projects, it is essential to understand the precise nature of the hydrocarbon fluids in terms of chemical and physical properties, phase behavior, and commingling tendencies. This understanding is essential to optimize completion and facilities design and reservoir-production strategies. Gas/liquid ratio, saturation pressure, and viscosity are fluid parameters that determine whether and how production is pursued. Phase transitions such as asphaltene onset, wax and organic-scale deposition, gas-hydrate formation, and diamondoid accumulation can reduce production substantially. Consequently, getting the correct answer at the beginning of a project is necessary.
Chain Failure by Bending on Deepwater Mooring Systems
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17238, "Failure of Chains by Bending on Deepwater Mooring Systems," by P. Jean, Single Buoy Moorings Inc.; K. Goessens, Total E&P Angola; and D. L'Hostis, DV Offshore, prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May.
The premature rupture of mooring chains of the Girassol buoy after only a half-year of service was caused by bending fatigue of the first free chain link inside the chain hawse (fairlead). Although the mooring system had been designed according to offshore industry standards, it failed because of this bending-fatigue mode. A study of this bending phenomenon led to a redesign of both the top chain segment size and the hawse connection, which now includes a new chain-connecting arm (CCA). A new method was developed to estimate the fatigue damage in the chain subjected to bending, which was used to design a new CCA for the Girassol buoy.

Introduction
The Girassol loading buoy was installed in September 2001 at the Girassol oil field off-shore Angola in 1350-m water depth. The buoy allows export, by use of two midwater 16-in. export lines, of the stabilized crude oil processed onboard the floating production, storage, and offloading vessel, moored 1 naut mile away.
The buoy is anchored to the seabed by means of three groups of three anchor legs. Before the incident, the anchor legs comprised collinear segments of 81-mm studded chains and 130-mm-diameter polyester ropes. Within each group, the legs are spread 5° apart, and the group centers are spread 120° apart. The chain segments are at the upper and lower ends of the anchor legs.
In May 2002, 235 days after buoy installation, one group of anchor legs (B4, B5, and B6) broke almost simultaneously, followed 1 month later by the rupture of another anchor leg (B1).
The ruptures in Anchor Legs B4, B6, and B1 occurred at exactly the same location—at the fifth link of the upper chain segment connected to the buoy inside a standard-type curved chain hawse—while Leg B5 broke in the upper rope segment. This rope-segment rupture was caused primarily by an earlier accidental cut of the rope through two-thirds of its section. The total rupture of Leg B5 followed the rupture of Legs B4 and B6 as a result of load transfer. However, the fifth link of Leg B5 was found severely cracked, thus confirming the same failure mechanism for all four legs.
Studies identified the root cause as the out-of-plane bending (OPB) stress (fatigue stress), combined with tension variations, occurring mainly in the fifth link inside the chain hawses. As Fig. 1 shows, Link 5 is the first link to oscillate with respect to the Link 4, which is fixed onto the internal curved shape of the chain hawse.