2008
GLOBAL OFFSHORE REPORT
An analysis of worldwide activity and potential
A SUPPLEMENT TO
2008
GLOBAL OFFSHORE REPORT
ACTIVITY OVERVIEWS REGIONAL OVERVIEWS TECHNOLOGY OVERVIEWS
ANNUAL REPORT INCLUDES EXPERT ANALYSIS OF TRENDS, REGIONAL ACTIVITY HIGHLIGHTS, AND TECHNOLOGY UPDATES.
With more than US $43 billion forecast in capital expenditure on floating production systems in the 2008 to 2012 period, and a projection that shallowwater projects will see noticeable growth during the same time frame, there is an industry-wide need to know what is going on around the world in offshore E&P. For this Global Offshore Report, industry specialists contributed expertise in the form of overviews that evaluate activity in seismic exploration, floating production, shallowwater projects, and subsea development. These renowned experts explain where activity will take place, what the hurdles are, and where the money will be spent. Within this publication, Hart editors take a look at specific geographical areas in terms of activity and E&P potential. And technical articles cover the spectrum from seismic tools to rig classification and utilization to riser technology and subsea production. Read on for an in-depth look at the offshore E&P industry and where it is going.
A SUPPLEMENT TO
2008
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GLOBAL OFFSHORE REPORT
ACTIVITY OVERVIEW
Exploration — Visualization Under the Sea .....................................................................4 Floating Production — Floating Production To See Substantial Growth........8 Shallowwater Prospects — Deep Returns On Shallow Pipedreams ........12 Subsea Production — Subsea Spending Continues to Rise ...............................16
Editor in Chief
BILL PIKE
Editor Special Projects
JO ANN DAVY
Contributing Editors
JULIAN CALLANAN MATTHEW DONOVAN LOUISE S. DURHAM PAAL T. GABRIELSEN DICK GHISELIN JOHN GREENWAY DR. ROGER KNIGHT STEPHEN P. NEWELL THOM PAYNE ALEX PEARCE DAVE RIDYARD STEVE ROBERTSON MICHAEL TANG ROGER TAYLOR STEPHEN TRAMMEL
REGIONAL OVERVIEW
From the Gulf of Mexico to the Caspian Sea, the offshore sector is heating up around the globe.
Africa ............................................22 South America .......................24 Gulf of Mexico ......................25 Southeast Asia ......................28
North Sea ..................................29 Central Asia ...........................32 Middle East ..............................36 Arctic ............................................38
Corporate Art Director
ALEXA SANDERS
Assistant Art Director
MELISSA RITCHIE
TECHNOLOGY OVERVIEW
Exploration: Wide Azmuth Wide Azimuth Adds Value........................................................................................................40 Exploration: New Vessel Design The Evolving Design of 3-D Seismic Vessels .......................................................................44 Exploration: 4-D 4-D Seismic Gains Traction .......................................................................................................48 Exploration: Nodes Autonomous Nodes Raise the Bar .........................................................................................52 Exploration: Electromagnetics The Business Impact of Seabed Logging..............................................................................56 Exploration: Deepwater Classification Offshore Designs Trending Towards Hybrids.....................................................................60 Drilling: Criteria Designs Keep Pace With Mother Nature ............................................................................64 Drilling: Drilling Rig Count Offshore Rig Market Boom Continues .................................................................................68 Production: Floating Production Innovations in Floating Production ..........................................................................................70 Production: Subsea Production Subsea Solutions Stretch the Imagination ...........................................................................74 Production: Riser Technology The Rising Tide of Riser Technology ......................................................................................78
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Production Director
JO LYNNE POOL For additional copies of this publication, contact Customer Service +1 (713) 260-6442
Business Development Custom Communications
MITCH DUFFY
Advertising Manager Custom Communications
Dawn Peek
Group Publisher
RUSSELL LAAS
Vice President, Publishing BRION D. PALMER Vice President, Consulting E. KRISTINE KLAVERS Senior Vice President and CFO KEVIN F. HIGGINS Executive Vice President FREDERICK L. POTTER President and Chief Executive Officer RICHARD A. EICHLER
Cover photo courtesy of Pride International
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BY STEPHEN TRAMMEL, IHS
Industry is looking for deepwater oil and gas, and technological advances in seismic imaging of ultra-deep, subsalt reservoirs continue to have a dramatic impact on exploration success and offshore seismic crew activity.
hile the Gulf of Mexico (GoM) has been the laboratory and model for subsalt geophysical advances, recent discoveries reported by Petrobras in the Santos Basin with billions of bbl of potential reserves from subsalt structures show how the revolution in better images will have a global impact. No one would argue against the primary importance of seismic as an exploration tool and that it is one of the best methods we have to mitigate risk. But the high-risk, high-reward deep reserves operators are targeting today have been difficult to image, especially under the distorting effect of salt formations. With ultra-deepwater wells costing US $50 to $100 million each and platforms running more than $1 billion, the last thing companies want are surprises. In spite of the expense of new seismic technologies like wide azimuth surveys and computer processing, improved images are paying off in a great return on investment. One of the top achievements for the modern oil and gas industry is the ability to image, analyze, and
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develop offshore subsalt reservoirs. The need for reserve replacement, meeting demand growth in developing countries, and the improvements in deep imaging are driving offshore seismic crew counts back up to levels exceeding any active crew numbers in the last 10 years, and doubling the counts from a low point in 2004. In fact, high-end seismic vessels are in great demand, and according to industry analysts, acquisition is backlogged as far as 2010 or 2012. By then, improved capacity will help reduce and even eliminate backlogs with offshore crew activity levels remaining strong well into the next decade. The strong growth in seismic activity in Far East waters is a clear indication of oil and gas demand growth in China and India, where work is under way to secure energy supplies for those developing economies. What kind of new geophysical technologies are helping to create the better images we see today? Houston-based International Association of Geophysical Contractors provided the following list. I Electromagnetic surveys; I Wide azimuth surveys;
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SEISMIC EXPLORATION ACTIVITY
I I I
New processing techniques and algorithms; New acquisition techniques and technologies; and Reservoir characterization modeling.
EM
Electromagnetic (EM) surveys employ seabed-logging receivers to detect energy that has been guided from a distant EM source by resistive bodies. EM energy identifies subsurface resistivity contrasts. Since hydrocarbon reservoirs are electrically resistive, the EM energy can be guided over a distance of several kilometers. A powerful EM source towed close to the seabed emits low-frequency energy into the subsurface. Some of that energy is guided with low attenuation by resistive bodies, such as hydrocarbon reservoirs. Processing and modeling is then used to create maps, cross sections, and 3-D volumes that show the location and depth of the potential reservoirs. This complex technology will continue to evolve and today is commonly combined with other seismic data.
WIDE AZIMUTH
Offshore, an “azimuth” is the angle of linear horizontal direction. Wide azimuth surveys create a much sharper image of subsalt prospects by illumination from multiple angles. It became obvious to those analyzing data that narrow azimuth surveys where a vessel towed streamers over one angle were not doing a good imaging job at greater depths. Seismic acquisition needed to be carried out over a wider area of water using more vessels, sometimes three or four boats with two serving as source vessels and two towing streamer recorders. This approach is expensive, and the process continues to be developed to cut down on the number of vessels required. Data can be acquired in multiple angles from a swath of water up to and exceeding 2.5 miles (4 km), compared to maybe 1.6 miles (1 km) at best in a narrow azimuth operation. The amount of new data coming in from wide azimuth acquisition required new and improved processing algorithms. Jerry Young, senior vice president of US imaging, CGGVeritas, notes that as the wide azimuth seismic data has become the data of choice for subsalt imaging, processing geophysicists have come under pressure to adapt the existing imaging
technology and develop novel approaches to exploit the full benefits of the added azimuthal information. Young says in addition to existing techniques, advances are being made to use all azimuthal components in data regularization for preprocessing and in tomographic inversion for velocity estimation. Unlike conventional narrow azimuth data, wide azimuth data potentially contains sufficient information for the detection of azimuthal anisotropy. When the subsurface strata exhibit azimuthal anisotropy, geophysicists must correct for this to avoid acquisition footprints and to improve resolution. The challenge lies in how to estimate and incorporate azimuthal anisotropy in imaging algorithms to achieve high-quality images and better seismic-to-well ties. Benefits include I Improved resolution and imaging; I Improved velocities; I Reduced acquisition footprint; I Reduced migration noise; I Improved reservoir definition; and I Improved fracture characterization. Young also emphasizes that in recent years, increasing computing power has become more economically available. This has sped up the development and application of new seismic imaging technology. Advanced seismic algorithms, such as 3D SRME for multiple suppression, reverse time
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Working offshore seismic crews international and US 10year comparison (graphs courtesy of IHS Inc.) www.EPmag.com | Global Offshore Report | July 2008
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ACTIVITY SEISMIC EXPLORATION
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streamer steering for repeatability to provide seismic data with broader frequency bandwidth and higher resolution. Q uses special filtering techniques, including more separation in the hydrophones and recording them separately to help eliminate the noise.
GETTING CLEARER IMAGES
Geophysical contractors are using other techniques to attenuate noise and give clearer images. PGS reportedly is able to replicate ocean bottom cable data acquisition, used in shallowwater applications, in deeper water by using two sensors in a streamer — one for motion detection and one velocity sensor. Other applications include solid streamers. Hydrophones are inserted into a streamer that contains a special injected foam instead of the traditional oil-based liquids. The advantage to the foam is a lack of vibration and lowfrequency bulge wave from the flexible housing of the streamer compared to a liquid-filled streamer. PGS is trying gel streamers for the same effects. Seismic continues to evolve from imaging to a reservoir characterization and reservoir management tool. Reservoir engineers are using geophysical data to create models that predict drainage patterns, fractures, and other reservoir attributes and to design injection plans. Drilling and production engineers can create well trajectory plans, proper well placement, and depletion plans. Combining seismic with nodal analysis and material balance techniques, simple decline curve analysis, and petrophysics creates a synergistic understanding of reservoir characteristics and resulting analogs that cannot be achieved by using any of the analytics by themselves.
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The most active offshore regions for crew activity
migration for complex structural imaging, and beam migration for imaging areas of poor S/N are now being routinely used to aid exploration and production activities, particularly for subsalt exploration in the deep waters of the GoM.
STACKED STREAMERS, Q TECHNOLOGY
Even with the significant advance in wide azimuth surveys, other acquisition improvements are required to get the most out of the recorded data. Some examples are the application of stacked streamers and Q technology by WesternGeco. Extraneous noise, also called ghosts, come from the water column, weather, sea conditions, and the seismic acquisition equipment —streamers and cables.
SEISMIC CONTINUES TO EVOLVE FROM IMAGING TO A RESERVOIR characterization
and reservoir management tool. Reservoir engineers are using geophysical data to create models that predict drainage patterns, fractures, and other reservoir attributes and to design injection plans.
In a stacked streamer configuration, two hydrophones are towed separately at a known depth of separation. The wave field separation is calculated to get rid of the ghosts. Q is the WesternGeco suite of advanced seismic services and technologies for enhanced reservoir delineation, characterization, and monitoring. According to WesternGeco, Q-Marine uses unique calibration, accurate positioning, and dynamic Deepwater discoveries with giant reserves like Atlantis, Mad Dog, Thunder Horse, Great White, Marco Polo, Tahiti, Tobago, and Jack plus the new Santos Basin Tupi and CariocaSugar Loaf are evidence that the technological advances in seismic acquisition and processing are providing big rewards for the industry’s investment in creativity. •••
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FLOATING PRODUCTION
TO SEE SUBSTANTIAL GROWTH
Results from “The World Floating Production Market Report 2008-2012,” recently published by energy industry analysts Douglas-Westwood, indicates strong growth in floating production system (FPS) installations over the next five years.
BY ALEX PEARCE AND STEVE ROBERTSON, DOUGLAS-WESTWOOD LTD. ecent years have seen a rapid expansion of the world’s floating, production, storage, and offloading (FPSO) fleet, prompted in part by an increased demand for drilling units, which has reduced the number of semisubmersible rigs available for conversion to production platforms. International legislation (introduced largely in response to the Exxon Valdez disaster), which phases in requirements that tankers be fitted with double hulls, provides further stimulus since conversion of otherwise obsolete single-hull tankers into FPSOs enables the profitable re-use of depreciated assets. FPSOs dominate the global floating production scene. At year-end 2007, there were nearly 190 FPSO deployments worldwide – 63% of all floating production systems, including production semisubmersibles, tension leg platforms (TLPs), and spars. The reasons for the popularity of FPSOs as host facilities are not difficult to work out. They contain large deck areas for processing facilities and plenty of vertical load-bearing capability (to resist mooring and riser loads), all at economical cost and with relatively short lead times, since tankers are produced in large numbers from shipyards worldwide. FPSOs also have the advantages of allowing more flexible oil distribution and providing storage capacity for produced oil, which can eliminate the need to install pipeline export networks. This is particularly relevant off West Africa, for example, where offshore pipeline infrastructure is limited and restricted to shallow water. Off Brazil, the existing offshore infrastructure is working close to capacity, and the extreme water depths of new fields mean that the cost of shuttle tanker offtake from FPSOs compares very favorably with the costs of installing additional export pipelines.
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FPS PROSPECTS BY REGION
Turning to the prospects for individual regions, the data indicate that significant growth is in store for the majority of the regional floating production system (FPS) fleets. Western Europe and Latin America have seen the most FPS deployments to date. Western Europe is
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FLOATING PRODUCTION ACTIVITY
3,000 m (>10,000 ft)
EUROPE
ASIA
AFRICA
SOUTH AMERICA
OVERVIEW AFRICA
West Africa has been an active area for E&P over the past year, and record levels of investment indicate that there is much more to come in the region.
BY JUDY MAKSOUD, EXECUTIVE EDITOR
GULF OF GUINEA LEADS DEEPWATER E&P
T
he biggest flurry of activity offshore Africa is in the Gulf of Guinea. The most sizable finds in the region were offshore Angola, where exploration activity has been heaviest. In January 2008, Total made a significant oil discovery in deepwater Block 14 in the Lower Congo Basin with the Lucapa-1 discovery well. Drilled in 3,940 ft (1,201 m) of water, the well encountered more than 279 ft (85 m) of oil. In February 2008, BP made its fifteenth discovery in Block 31 with Portia, and in May, Eni, with partner Sonangol, made anoil find in deepwater Block 15/06, which lies 217 miles (350 km) north of Luanda. The Sangos 1 wildcat well, the first exploration well to be drilled in Block 15/06, was drilled in a water depth of 4,426 ft (1,349 m). Eni plans to drill additional wells in the surrounding, high-potential areas in the western part of the block.
In February 2008, Total had two more finds offshore Angola in ultra-deepwater Block 32. The Manjericão-1 well, in the central part of the block, tested more than 5,000 b/d of oil, while the Caril-1 well, to the northeast, produced at a rate of 6,300 b/d from a selected interval. In May of last year, Total and Sonangol announced two new oil discoveries in Block 32: Cominhos-1 and Louro-1. And, in August, the eleventh exploration well on the block hit oil. Drilled in a water depth of 5,577 ft (1,700 m), the Colorau-1 well lies 10 miles (16 km) northeast of Manjericão. In December, Total found oil with the ultra-deepwater Alho-1 well in the same block. Activity offshore Nigeria is primarily development. Chevron Nigeria Deepwater Ltd. began developing the Usan field in February 2008. First production is expected in late 2011, with peak production of 180,000 b/d. Usan is 62 miles (100 km) offshore in 2,461 ft (750 m) water depth in OML 138. In June 2007, the Nigerian National Petroleum Corp. and Total launched Phase 2 of the shallowwater Ofon field development project, which is ongoing. Phase 2 is expected to add an estimated 350 million boe in reserves and to allow output to reach 100,000 b/d by the end of 2010. This phase of development will also eliminate gas flaring in >>
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AFRICA OVERVIEW
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GULF OF MEXICO OVERVIEW
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OVERVIEW GULF OF MEXICO
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NORTH SEA OVERVIEW
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OVERVIEW NORTH SEA
Smaller operators have also been active, including Lundin, which extended its Nemo field in the southern North Sea increasing reserves to 20 to 30 million bbl last February. Dong, meanwhile, confirmed the Oselvar field holds an estimated 40 million boe. In June, Marathon Oil began production at the Alvheim field, which is expected to reach an estimated 13,500 boe/d by the end of the year. The Vilje field, a tieback to Alvheim, should now be under way. In January 2008, Statoil Hydro brought its Volve field onstream, and Alve, Gulltopp, and Oseberg Delta tiebacks will follow soon.
UNITED KINGDOM PLOWS AHEAD
Exploration prospects in the United Kingdom are expected to rise. Analysts at Hannon Westwood recently reported that about 220 exploration and appraisal wells are planned for the United Kingdom within the next two years. Approximately 65 wells were drilled last year. The report indicates this number will be maintained in 2008. Many of these wells will be carried out through farm-in agreements.
In the northern North Sea, the Jura oil and gas field achieved first gas in May. Located on Block 3/15 about 275 miles (440 km) northeast of Aberdeen, the field has proved reserves of 170 million bbl of oil. Discoveries have also helped boost the standing for the United Kingdom Continental Shelf (UKCS). In February, Oilexco delineated its Huntington find in Block 22/14b. The operator is currently seeking approval for field development with an expected startup in late 2009. Bridge Resources successfully tested its North Sea Durango 48/21a-4z well. The prospect tested at a rate of 42.5 MMcf/d of gas and an average 1,341 b/d of condensate on a 1-in. choke. Upon approval, the company plans to tie in the well to the Waveny platform about 9 miles (14 km) to the northeast. First gas is expected in October. ConocoPhillips discovered more gas/condensate on its Jasmine concession in Block 30/6, which is close to the Judy hub in 30/7. Antrim announced this month that it is accelerating drilling activity at the Causeway field. The company plans to focus on the East Causeway field area to evaluate the Brent sandstone and the deeper Etive formation. >>
norway’s offshore petroleum sector is expected to provide us $70 billion in 2008. this is $10 billion more than earlier estimates due to rising costs of oil and gas.
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OVERVIEW CENTRAL ASIA
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OVERVIEW CENTRAL ASIA
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OVERVIEW ARCTIC
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ARCTIC OVERVIEW
figure 1. location of the laptev sea shelf province and assessment units (Image courtesy of USGS)
<< from several countries and organizations indicate that two or more total petroleum systems might exist in the study area. Because of possible mixing of petroleum, the Jurassic-Cretaceous-Paleogene Composite Total Petroleum System (TPS) was identified for the West Laptev Grabens AU. Geologic scenarios evaluated for the assessment were based on the existence and distribution of source rocks of these ages. The Paleogene TPS was identified for the Anisin-Novosibirsk Basins AU. The greatest geologic uncertainty for the assessment of both assessment units is with respect to the petroleum charge. Analyses of natural gas collected from bottom sediments and near-bottom waters of the Laptev Sea Shelf indicate the presence of mature oil-prone marine source rocks, presumably of Paleogene age. Upper Jurassic (Volgian) organic-rich mudstone might also be an important petroleum source rock in the study area, as are synrift Lower Cretaceous and Paleogene carbonaceous and coaly rocks. Major synrift reservoir rocks are likely to be shelf and slope siliciclastic sediments deposited by deltas
of the paleo- and present-day Lena River. It is uncertain whether prerift reservoir rocks are present. Traps for petroleum accumulation could include extensional structures and stratigraphic traps associated with shelf sediments.
RESOURCE SUMMARY
The US Geological Survey assessed undiscovered conventional, technically recoverable petroleum (discovered reserves not included) resulting in the estimated mean volumes of a probability distribution of approximately 3,069 million bbl of crude oil, 32,252 billion cf of natural gas, and 861 million bbl of natural gas liquids. The greatest volume of undiscovered petroleum is estimated to be in the West Laptev Grabens AU.
Editor’s note: Information in this article was taken from Klett, T.R., and others, 2007, Assessment of undiscovered petroleum resources of the Laptev Sea Shelf Province, Russian Federation: US Geological Survey Fact Sheet 2007-3096.
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BY ROGER TAYLOR, CGGVERITAS
Wide-azimuth towed-streamer and ocean bottom cable surveys are opening new horizons offshore.
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ith the continuing development of wideazimuth (WAZ) seismic surveying, seismic exploration for oil and gas is undergoing a revolution similar to the one experienced in the 1980s with the move from 2-D to 3-D.
WHAT IS WAZ?
Think of a seismic shot as analogous to dropping a stone into a pond. The waves propagate outward in all directions and, if we want to record the whole wavefield adequately, we must have receivers over the entire area. However, conventional 3-D surveys, especially marine towed streamer, record only a narrow off-end swath of this wavefield, i.e., multiple 2-D stripes of a 3-D object. To achieve an optimum image, therefore, we need both wide-azimuth recording and sufficiently dense sampling to obtain a full representation of the seismic wavefield. For many years, land and seabed surveys have been shot with wide-azimuth geometry but usually with a sparse or undersampled design. This has been improved with modern technology, and there is a clear industry trend toward denser sampling. At the same time, we have also seen a move to wide- and multi-
azimuth marine surveys, both of which provide a fuller sampling of the wavefield. The early stages of the change to wide-azimuth marine seismic occurred in the Gulf of Mexico (GoM), where CGGVeritas shot the industry’s first towedstreamer wide-azimuth survey in collaboration with BP in order to improve illumination beneath tabular salt. In parallel, multi-azimuth surveys were undertaken in both Egypt and the southern North Sea. One of the major findings of the early GoM and offshore Egypt surveys was that, along with improved subsalt imaging, multiple and noise suppression could be significantly improved by wideand multi-azimuth shooting geometries. With this understanding, the expected benefits for other areas, both offshore and onshore, become apparent. These include providing clearer images of sub-basalt targets, reservoirs beneath rugose seabeds, and deep targets with weak signal strength. Dense wideazimuth recording can also provide more reliable characterization of naturally fractured reservoirs.
TOWED-STREAMER WIDE-AZIMUTH
The experience gained from this first towed-streamer wide-azimuth survey with dedicated source boats in large-scale multivessel operations pointed the way to solutions for managing many of their inherent operational complexities and difficulties. This led directly to the development of a new generation of navigation systems allowing enhanced geophysical quality and operational efficiency.
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TECHNOLOGY EXPLORATION
figure 1a. Narrow-azimuth final PSDM section
(Figures courtesy of CGGVeritas)
figure 1b. fast-trax, wide-azimuth psdm section
Pioneering modeling and simulation work for the design of this and subsequent surveys enabled the derivation of metrics to define the balance between acquisition effort and wide-azimuth data quality, and it is now possible to optimize the design of any towed-streamer wide-azimuth survey. The ideal combination of speed of acquisition, effective illumination, and data quality can be readily defined for large-scale, cost-effective projects. Processing and imaging tools have been enhanced for application to wide-azimuth data with associated development of pre-processing sequences for efficient noise and multiple removal, statics computations, and regularization of data. This means that it is possible to deliver processed wide-azimuth data of the highest standard, irrespective of survey configuration and size. Until now, much of the processing of 3-D surveys has involved 2-D assumptions with the notable exception of 3-D imaging. Some 3-D surface-consistent processes are also used on land and seabed surveys, while 3-D surface-related multiple elimination has proved successful on marine surveys in recent years. The transition to dense wide-azimuth surveys allows us to adopt full 3-D algorithms throughout the processing and imaging sequence. In many circumstances it is a requirement to use full 3-D solutions to gain the most value from the data to optimize the multiple and noise suppression and to preserve azimuthal information for subsequent attribute analysis.
WORLDWIDE APPLICATIONS
Wide-azimuth surveying was initiated in the GoM to address complex imaging issues beneath salt. However, the technique is also highly appropriate for other areas of complex structural geology or areas where velocity contrasts are significant. The wide-azimuth technique can be beneficial in other areas where salt causes imaging problems, such as the central and southern North Sea in the United Kingdom and the Aptian salt basin of the west coast of Africa, especially offshore Angola and in Gabon’s southern basin, which is densely populated with salt diapirs. Wide azimuth is also expected to play an important role in unlocking the pre-Caspian basin of Kazkhstan, home to Kashagan, the largest oil discovery of the last 35 years. Areas of complex structural geology such as overthrust belts also benefit from the technique, especially where high-velocity, previously deeply buried strata have been thrust over younger, lower-velocity rocks. Such conditions occur in many parts of the world, including the American and Canadian Rocky Mountains and the Tien Shan basin of China. Other basins where wide azimuth is applicable include those where deep sedimentary geology is overlain by high-velocity basalts, which are notoriously difficult to penetrate by conventional seismic methods because of their heterogeneous nature. Thin layers of low-velocity weathered basalt are sandwiched
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TECHNOLOGY EXPLORATION
between extremely high-velocity unweathered layers of “fresh” basalt. This type of environment is typical of the Faroe-Shetland basin in the north Atlantic.
quality and continuity of the subsalt reflectors show a significant improvement over previous conventional narrow-azimuth data.
DATA LIBRARY
Following the successful completion of four wideazimuth contract projects, CGGVeritas began building a wide-azimuth data library. The company has three significant surveys in progress, one of which is already available with Fast-Trax imaging, over key acreage within the US Minerals Management Service Central GoM planning area. These wide-azimuth volumes offer higher-resolution, better illumination, improved subsalt imaging, and optimal multiple and noise suppression. They are available with high-end processing and imaging technologies applied throughout, allowing the identification of potential new plays. The CGGVeritas Walker Ridge wide-azimuth survey resulted in the recording of approximately 460 blocks of data. The acquisition program used four source vessels shooting into a 10-streamer recording array towed by a high-capacity vessel with a flexible deployment, allowing targeted high-density recording over two recent Lower Tertiary discoveries. Results from the survey in the targeted subsalt sediments are particularly impressive; the
SEABED – OBC AND OBS
Wide-azimuth seismic surveying using seabed recording has been performed for many years. Seabed surveys have been mainly used for specific geological problems such as imaging through gas clouds using converted waves or as a solution to operational problems such as proximity to production platforms. The advent of towed-streamer wide-azimuth surveys has highlighted other benefits such as illumination, noise and multiple suppression, and fracture estimation. A comparison of towed-streamer and seabed geometries shows that they have a high degree of reciprocity; the benefits and experience of wideazimuth towed-streamer surveys apply just as well to seabed recording but with the added benefits of multicomponent data. The converted wave (PS) data recorded by multicomponent systems is particularly sensitive to azimuthal anisotropy and can be a source of valuable information for fracture characterization. In an example offshore Qatar, a wide-azimuth OBC dataset was acquired over a carbonate reservoir undergoing secondary recovery by waterflood. A seismic fracture characterization project was used to map highly permeable fault zones and fracture corridors for well planning and reservoir management. Comparison with well data resulted in good correlations between seismic azimuthal anisotropy, fracture intensity, and permeability. Both the P and PS data from the multicomponent OBC survey allowed the generation of seismic attribute anisotropy maps figure 2. The normalized azimuthal amplitude anisotropy intensity map (right) is shown with overlay of interpreted faults (black). Well data is shown with the mud- to highlight zones of high fracture loss points (yellow) indicative of permeable fracture zones. outlined in red is the intensity and permeability. This known conductive fracture corridor, which correlates with high-anisotropy inten- improved well planning by reducsity values and in green an area of low fracture intensity. the ps azimuthal timeing uncertainty and providing delay map for the reservoir (left) is consistent with the p-wave amplitude data, independent estimates of seismic reinforcing the interpretation of seismic-based fracture intensity estimates. fracture intensity. •••
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the evolving design
of 3-D seismic vessels
Purpose-built vessels ensure more productivity in seismic surveying.
ramforms are designed to overcome hull deficiencies.
(Images courtesy of PGS)
EXPLORATION TECHNOLOGY
BY JOHN GREENWAY, PETROLEUM GEO-SERVICES ith the current upsurge in E&P activity, and exploration activity in particular, the last two years have seen a significant increase in the number of new 3-D seismic vessels being brought to market by several seismic fleet operators. Over the next two years, the industry will see more, with additional vessels already under construction or conversion.
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PURPOSE-BUILD OR CONVERSION
The natural incentive by fleet operators to come quickly to market has encouraged many to invest in conversions of existing vessels rather than designing purpose-built 3-D seismic vessels from the outset. While satisfying the requirement to capitalize on strong current market conditions, many of these vessel conversions lack certain fundamental characteristics that are required for efficient operations. Chief among these are power trains, propulsion systems, and load-carrying capacity. Many different vessel types have been selected for conversion to 3-D seismic operations recently. Common for all of these vessel types, however, is the fact that the original platform was purpose designed for something else — to travel at high economic cruising speeds for relatively short durations (three to four weeks) port to port. High-capacity 3-D seismic vessels need to be able to operate at slow speeds of around 5 knots, delivering around 120 metric tonnes of forward thrust for extended periods of time — the longer the better. At normal towing speeds and with large towed configuration, propulsion systems on converted hulls are often operating at more than 90% of their designed maximum output day in and day out. This puts enormous strain on motors and gears, potentially resulting in excessive wear and failures. The second major drawback with conventional vessel designs for seismic operations lies in the requirement for large load-carrying capacity above the water line. A large-capacity seismic vessel needs to carry upwards of 400 metric tons of seismic equipment. For seismic operations, this load needs to be carried above the water line to be able to deploy and retrieve the towed equipment efficiently and safely (Figure 1). Squeezing this volume of equipment into
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TECHNOLOGY EXPLORATION
Figure 1. Seismic vessels must have enough deck space to store tons of equipment.
a conventional hull generates hull stability challenges. It also forces the equipment to be arranged on separate decks or in tandem arrangements along a significant portion of the vessel’s length. This kind of arrangement severely complicates the efficiency of gear handling during operations. In short, conventional hulls are designed long and slim for speed during short operating periods with cargo weight low down and with a minimum of complex human or mechanical activity toward the stern. Seismic survey vessels ideally should be just the opposite.
A DESIGN BREAKTHROUGH
When Petroleum Geo-Services (PGS) was planning its new generation of seismic survey platform about 10 years ago, all of these deficiencies with conventional hull shapes were identified, and a solution was sought to overcome them. The result, now in its third generation, was the Ramform concept. The latest version of the design, a vessel called the Ramform Sovereign, was recently launched on the west coast of Norway. The Ramform Sovereign illustrates many of the features the designers and builders have incorporated for one single purpose — to collect maximum amounts of seismic data, as quickly, safely, and reliably as possible. The first obvious feature of the vessel is the hull shape. At just more than 300 ft (100 m) in length, the
vessel is not long by modern standards, but with 130 ft (40 m) in the beam at the stern, the hull takes on a futuristic appearance. This is strikingly different from conventional slim hulls, and while the vessel is no slouch at 16 knots cruising speed, it is clearly no ocean greyhound, despite about 30,000 hp of propulsion capacity. For acquiring seismic data at slow speeds, the unusual hull shape comes into its own. The hull shape offers enormous volume for its length and gives the ship a load-carrying capacity equivalent to conventional vessels many times its size. This allows the operator to install massive amounts of seismic equipment with no compromise to stability or work space. The vessel is equipped to tow up to 22 acoustic receiver cables – more than twice the capacity of most conventional vessels (Figure 2). This translates to higher productivity in operations, which is advantageous to both owner and customer. The volume also allows for extreme fuel capacity of about 6,000 metric tons, offering extreme survey endurance. As an illustration of what this means in practice, the vessel would be able to sail twice around the planet without having to stop to refuel. The ability to tow huge receiver spreads and the productivity advantage this delivers are compelling advantages for any vessel in commercial operations. It is not without its own challenges however.
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Figure 2. Airgun arrays are steerable and are linked to the vessel’s navigation system.
Figure 3. Workboats are designed to raise receiver cables for maintenance.
Trailing well over US $100 million worth of sensitive seismic instrumentation behind the vessel efficiently requires that the in-sea equipment be maintained properly. The vessel is equipped with two workboats for this purpose, double the complement of conventional vessels, again made possible by the specialized characteristics of the ship. Each workboat, 30 ft (9 m) long, has been custom designed to be able to swiftly and safely raise receiver cables for maintenance (Figure 3). For crew changes, the vessel sports the world’s first roll-compensated helideck, allowing safe helicopter landings in conditions where landings would normally be too hazardous to attempt.
With receiver cables being so long in the water between deployments, marine growth on the cables becomes an issue, particularly in warmer climates. To counter this, the company has designed its own automated device for removing stubborn growth (such as barnacles), which negates the need for equipment retrieval from the sea. Additionally, the company is reviewing a cable skin material that itself repels attachment of marine organisms by nonchemical means. A new and advanced autopilot system has been installed that steers the vessel’s course and speed according to pre-defined survey parameters, thereby further enhancing productivity.
ADVANCED EQUIPMENT
On the equipment side, there are also several features that can be expected to find their way onto other new seismic vessels in the future. For instance, the sources are equipped with devices attached to the airgun arrays that enable the sources to be steered rather than simply towed passively behind the vessel (Figure 2). Sophisticated software interfaced to the vessel’s seismic navigation system allows the source arrays to steer predetermined tracks to repeat the source positions of previous surveys. This is of great benefit for advanced 4-D surveying.
CREW COMFORT
In the current environment of competition for recruitment and retention of offshore crews, it is important to offer a comfortable workplace onboard. All cabins on the Ramform class vessels are equipped with personal DVD systems. There is a large gymnasium as well as a relaxing environment for the off-watch crew. The Ramform Sovereign offers insight into current thinking and the focus for future 3-D seismic vessel design. It represents the hunt for efficiency and productivity enhancements over a range of technology areas in a bid to create the edge to succeed in a highly competitive arena. •••
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BY MICHAEL TANG, WESTERNGECO
4-D SEISMIC
gains traction
New acquisition, processing, and interpretation techniques are enabling 4-D seismic technology to enjoy more widespread use.
he growth of time-lapse applications over the past 10 years has been vast, and an increasing number of monitoring surveys are taking place each year. With the need to improve recovery from existing reservoirs, 4-D seismic methods are high on everyone’s agenda. Time-lapse seismic is one of the few tools that allows us to see what is happening in the reservoir between the wells. The method has been proven to have substantial economic benefits in many areas of the world. In fact, independent industry analysts have assessed that since 1996, 4-D surveys have resulted in an added value of more than US $4 billion in the North Sea region alone. Clearly, 4-D surveys have a high economic impact.
RETRACING OUR STEPS
The time-lapse, or 4-D, seismic method involves acquisition, processing, and interpretation of repeated seismic surveys over a producing hydrocarbon field. The objective is to determine the changes occurring in a reservoir as a result of hydrocarbon production or injection of water or gas into the reservoir by comparing the repeated datasets. A typical final processing product is a time-lapse difference dataset. The seismic data from Survey A is subtracted from the data from Survey B. The difference should be close to zero except where reservoir changes have occurred. Repeatability is essential to the effectiveness of 4-D time-lapse seismic projects, whereby surveys are repeated after a period of hydrocarbon production, typically between one and two years.
T
the western spirit is the seventh Q-Marine vessel to join the WesternGeco fleet.
(Photo courtesy of WesternGeco)
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However, the effect of changes in reservoir conditions on the seismic data can be very subtle, demanding high-quality seismic acquisition and processing. From an acquisition perspective, it is close to impossible to exactly repeat all of the parameters of a past 3-D survey. Differences between survey vintages can obscure the subtle indications of fluid movement. The differences in the positions of sources and receivers from one survey to the next are a major cause of this non-repeatable noise. There are also several factors contributing to survey instability or differences between surveys, such as variable source output, variable receiver sensitivity, and inaccurate navigation data. Environmental effects such as tidal variations and changes in noise patterns also affect the repeatability of the time-lapse data. It is therefore essential to be able to accurately retrace your steps. While data processing that takes into account the survey instabilities is crucial, this can be a vast challenge, considering that in-sea equipment extends several miles behind a vessel and is affected by ocean swell, waves, and currents. A 4-D image is only as good as the 3-D images that are used and the degree of repeatability between the surveys. Only by preserving amplitude information can the resolution be improved by using the seismic inversion process. A number of successful tests have been performed where the difference from inverted data has been analyzed. Often, the change in overburden and underburden stresses caused by reservoir compaction and hydrocarbon production are not analyzed when performing 4-D analysis. However, it has been shown in a number of areas that the changes in the overand underburden contribute significantly to 4-D response.
This requires the use of geomechanics on the 4-D arena, which is not commonly practiced.
DEVELOPING TECHNOLOGY
To gain advanced results, a calibrated marine source system is necessary for limiting shot-to-shot variations, which can degrade the seismic data resolution. Highaccuracy positioning through the integration of a dense acoustic network can encompass the full insea spread. Calibrated hydrophones provide better amplitude stability in field and processed data, ensuring a significant improvement in repeatability. Single-sensor technology provides a fundamentally better 4-D measurement, and these technologies are packaged in the Q-Marine system. Until recently, vessels were manually steered so that source positions follow pre-plot positions while devices on the streamers enabled vertical and lateral steering to keep receivers as close as possible to the positions of a previous survey. This system allows excellent positioning repeatability in areas of good current conditions. However, it remains difficult to accurately predict the behavior of the towed spread and vessel in a dynamic marine environment. Even small differences in the distortion patterns of the two different datasets cause residual primary leakage on time-lapse difference data.
TAKING ACQUISITION, PROCESSING FURTHER
Recently, WesternGeco developed a new addition to the Q-Marine system called DSC, dynamic spread control. DSC provides independent steering of the sources in addition to the Q-Marine steerable streamers. The technique enables unsurpassed repeatability for 4-D timelapse studies and increased accuracy in Q-enabled over/under and rich-, wideand full-azimuth surveys.
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TECHNOLOGY EXPLORATION
“AS 4-D ACCEPTANCE CONTINUES TO GROW RAPIDLY OUTSIDE
the North Sea, more surveys will be shot in more places, and, consequently, the industry will be faced with more challenges. For example, there will be a need to reposition sources and receivers for time-lapse coil shoots.”
Using information from the previous survey and a dense in-sea real-time acoustic positioning network, the 4-D steering controller automatically steers the vessels, sources, and streamers to achieve the best possible 4-D match. The whole process is complemented by a new planning and evaluation software. DSC was field tested during a four-vessel wideazimuth survey in the Gulf of Mexico. The results from the test showed that with just automated vessel steering, it is possible to achieve below 33 ft (10 m) of crossline difference between the sources. However, using the full suite of DSC results evidenced an achievement of better than 20 ft (6 m) crossline at 2-sigma level. The vessel equipped with DSC was able to keep the sources much closer to the baseline than the vessel that was steered manually. While highly accurate 4-D is the foremost target of this effort, there are other differentiating benefits as well. DSC can also be used to improve coverage and reduce infill. Consequently, the package can also be used in conjunction with conventional (sellup) and novel acquisition techniques. WesternGeco has also developed 4-D processing methods appropriate for all repeated surveys. The methodology squeezes out the non-repeatable elements from the process and is equally applicable to data acquired with or without Q-Technology. The methodology also compensates for survey instability effects as far as possible without resorting to statistical matching techniques, as these may remove valuable 4-D signal. The flow is designed in such a way that subsequent monitor surveys can be handled without reprocessing the previous datasets. Additionally, the company has developed methods that allow time-lapse seismic data to be used to understand changes in stress fields in the subsurface, which provide direct information about conditions within the reservoir. These methods depend upon accurate measurements of changes in reflector timing between surveys. It is critical that the 4-D processors correct spurious time differences while preserving genuine ones.
THE RESULTS DELIVERED
The Western Spirit, the seventh Q-Marine vessel, was launched in June 2007 and immediately began work on a high-specification 4-D survey in the North Sea. The reservoir was almost 16,400 ft (5,000 m) beneath the seabed and was experiencing very high pressures and temperatures. The field came onstream in November 2005 with daily production of 125,000 bbl of condensate and just over 635 MMcf (18 million cu m) of rich gas. Due to production, the pressure had dropped significantly in all of the producing wells. The objective of the 4-D survey was to identify areas where the pressure was not dropping as fast as it was in others. The original baseline 3-D survey was acquired in 2003 by the Geco Topaz, aiming at straight lines and minimum possible streamer feathering to maximize potential future repeatability. The Western Spirit, deploying eight streamers, completed acquisition of the repeat survey in July 2007 and, despite less predictable ocean currents and higher natural feather relative to the baseline survey, delivered good positioning repeatability. About 95% of the time, the Western Spirit was able to position the sources less than 8.2 ft (2.5 m) from the planned position. And 95% of the time, the vessel repeated the feather angle within a margin of less than 2.5°.
FUTURE 4-D
As 4-D acceptance continues to grow rapidly outside the North Sea, more surveys will be shot in more places, and, consequently, the industry will be faced with more challenges. For example, there will be a need to reposition sources and receivers for time-lapse coil shoots. There is also a need to develop the ability to exert steering force while keeping steering noise to a minimum. However, with differentiated technologies offering a complete 4-D acquisition and processing solution from feasibility studies to inversion, the hope is that new surveys will continue to go back to exactly where they were previously conducted. •••
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BY LOUISE S. DURHAM, CONTRIBUTING EDITOR
autonomous nodes
raise the bar
any of the petroleum reservoirs E&P companies are targeting today are unusually complex features, and they often occur in hostile drilling environments (i.e., ultradeep water, ultra-deep traps, etc.). This has triggered a demand for an array of new tools to expedite evaluation and recovery of hydrocarbons. Given that superior images are a crucial element to accurately drill and ultimately produce these challenging targets, much of the needed technology is seismic data-related. Geophysical providers are working at top speed to provide the necessary tools to acquire seismic data that will yield the best possible subsurface picture. Because seismic data acquisition historically has been characterized by the deployment of sometimes huge volumes of expensive and cumbersome high-maintenance cables, it is particularly noteworthy that the data acquirers are rapidly moving to cablefree acquisition as the method of choice.
Nodes take the guesswork out of offshore exploration and development.
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Fairfield Industries now provides completely cablefree nodal acquisition technology to acquire reservoir-grade data. The company’s self-designed deepwater Z3000 node system – which acquires true all-azimuth seismic data by recording in all directions – was first used for commercial application at the BP-operated Atlantis field in the Gulf of Mexico (GoM) in 2005. The Atlantis project required deployment and retrieval of nodes coupled to the seabed at 1,628 locations spread over 93 sq miles (240 sq km) at water depths between 4,593 and 7,218 ft (1,400 and 2,200 m). The purpose of the project was to acquire wideazimuth data to overcome imaging problems related to the illumination of subsalt structures. All-azimuth illumination is essential to accurately image reservoirs that are partially obscured by salt bodies or other velocity complications.
DATA ACQUISITION
The Z3000 technology employs a straightforward approach to data acquisition. “Each autonomous node in this 9,843-ft (3,000m) depth-rated system is an independent, self-contained unit with a battery and highly accurate clock,”
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said Steve Mitchell, vice president and division manager at Fairfield. “When coupled to the seabed to acquire data, the lack of a hard link between units overcomes noise issues common to cable systems, enhancing vector fidelity. “The nodes are deployed on the seafloor using the familiar remotely operated vehicles, or ROVs,” Mitchell said. “A dual-source vessel completes the equipment requirements.” Following the successful outcome of the Atlantis program, Fairfield moved quickly to implement the Z3000 technology in a project for Shell at the Deimos field in approximately 3,280 ft (1,000 m) of water in the MissisFigure 1. The Z3000 and the Z700 sippi Canyon area of the GoM. (Images courtesy of Fairfield Industries) The Deimos survey required about 80 days from mobilization to demobilization and covered close to 52 sq miles (134 sq km). Node spacing was approximately 1,312 ft (400 m) with survey. Normal positional accuracy can be better than a 164-ft (50-m) source line separation and 164-ft 16 ft [5 m] – that alone makes it 4-D capable.” This was evident in the Atlantis survey, where the (50-m) source separation. The less-than-2% dropout rate on the nodes deployed is valid testimony to the difference between the ROV’s estimate of position when the nodes were deployed and the ROV’s success of the survey. estimate of position when the nodes were retrieved MULTIPLE APPLICATIONS was evaluated. Nodes can be a well-suited solution for a variety of “There were differences of 16 ft [5 m] or less for situations. For example, they’re a natural fit in the 75% of the nodes,” Mitchell noted. “Given that the realm of time-lapse seismic implementation, more water depths were close to 7,218 ft [2,200 m], this commonly known as 4-D. was a concrete validation of the effectiveness of this The use of nodes as a 4-D tool is destined to move subsea positioning system.” beyond the now-common practice of monitoring fluid Another example of the advantage of nodes is movement in the reservoir. In today’s price environment, found in the prolifically productive deepwater fields operators are inclined to take a hard look at the poten- in various parts of the world where gas clouds make tial for time-lapse seismic as a reservoir management it difficult to illuminate the geology using conventool to maximize economic return on their assets. tional seismic acquisition technology. Seismic surveillance has already proved to be a “Multicomponent, or 4-C, is a must in these situavaluable means of conducting reservoir management tions, as gas is spongy to P waves and causes attenin North Sea fields. The deepwater GoM also is a uation and scattering,” Mitchell said. “Shear waves prime target for this application given the combina- don’t see this. tion of huge assets and mega-high well costs, leaving “Our nodes are naturally 4-C capable, having little room for error when it comes to well placement. hydrophones and 3-component geophones – we can use them to see through gas clouds in deep water.” REPEATABILITY Deep water is but one environment where nodal “Node placement using ROVs ensures positional accu- technology is destined to become the tool of choice racy and repeatability,” Mitchell said. “Repeatability in the seismic data milieu. is a necessary prerequisite for high-quality 4-D seisIn fact, Fairfield is preparing to launch its shalmic, and every node survey as a byproduct is a 4-D lowwater Z700 operating system near year’s end. The
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TECHNOLOGY EXPLORATION
Figure 2. Nodes are deployed at BP’s Atlantis field in 7,000 ft (2,000 m) of water.
system currently is in Beta 2 testing and has undergone numerous field trials, where it performed successfully. Simplicity is the key enabling feature of the widespread applicability of the shallowwater Z700 system, according to Paul Bourgeois, business development manager at Fairfield. “The nodes are deployed by a high-tensile-strength rope, which eliminates the need for bulky, expensive cable with its frequently failing connectors,” Bourgeois said. “Using rope for deployment offers still another advantage of this type system as the operator can hook as many units as needed onto the rope, and the distance between the individual nodes can be adjusted as needed – all of this contributes significantly to greater efficiency and lower acquisition costs.” The Z nodal technology is suitable for any type of play, including the active shallowwater deep gas play in the Gulf. The ability to acquire true, allazimuth data to attain the ultimate image of the deep unexplored environs in this region will significantly enhance the operators’ ability to define optimal drilling targets. A number of significant discoveries have occurred in this shallowwater deep gas play, and many operators are abuzz over a current attempt to score a find in the ultra-deep horizons at more than 25,000 ft (7,625 m). McMoran has re-entered the Blackbeard West well in approximately 72 ft (22 m) of water at South Timbalier Block 168. The well was temporarily abandoned by operator ExxonMobil in 2006 after reaching a measured depth of 30,067 ft (9,170 m). The current plan is to drill to a proposed total depth of 31,267 ft (9,536 m) to evaluate the deeper targets and possibly deepen the hole to as much as 33,000 ft (10,065 m). The anticipated commercial debut of Z700 could be timely indeed, should Blackbeard ultimately open the door to a widespread ultra-deep gas play on the shallowwater shelf. This no doubt would be the catalyst for a whole new approach, such as nodes, to acquire superior quality data for enhanced imaging. Fairfield is also readying a land system, which is on the cusp of going into prototype mode. “We definitely see the market demand building for nodes,” Mitchell said, “so we’re absolutely excited about the future.” •••
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the business impact
of seabed logging
BY DAVE RIDYARD AND PAAL T. GABRIELSEN, EMGS
Electromagnetic surveying, a relatively new technique, is coming into its own in offshore applications.
good time to review whether the technology is on track to meet the commercial expectations of the pioneers.
SEABED LOGGING
It is well known that rocks with hydrocarbon-filled pore spaces exhibit higher electrical resistance than those with brine-filled pore spaces. This property has been exploited successfully by the borehole logging industry for more than 75 years. The biggest problem with a borehole resistivity log, of course, is that you have to drill the borehole first. In the late 1990s, Terje Eidesmo and Svein Ellingsrud, then researchers at Statoil, realized that thin resistive layers could partly guide electromagnetic fields and that this phenomenon could be observed prior to drilling the borehole. The process is straightforward. A powerful electric dipole source is towed behind a ship (Figure 1). As the electric field propagates through the subsurface, it is perturbed by any buried resistors. Seabed sensors are used to log the observed electric and magnetic fields. These data can be processed to form an image of the subsurface resistive structures, and resistivity volumes can be interpreted together with seismic
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eabed logging (an application of electromagnetics, or CSEM, for hydrocarbon exploration) was first used to detect offshore hydrocarbons in 2000 offshore Angola and 2001 offshore Norway. In the years since that pioneering work, the technology has been used in a growing number of commercial applications. EMGS alone has conducted more than 350 projects. This is a
<< Figure 1. Seabedlogging operations.
(Figures courtesy of EMGS)
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<< Figure 2. 3-D seabed-logging surveover the western Troll oil and gas field carried out in 2008. The resistivity anomaly map is integrated with seismic and field outline from the Troll oil and gas field. Yellow is low resistivity anomaly, and orange is high. Note how well the western oil field is delineated, with small variations of only 10% to 20%. In contrast, the gas field to the right has responses of up to 250%.
(Data courtesy of StatoilHydro)
Another way to look at this is to consider overall exploration success rates in areas where seabed logging has been widely applied. Figure 4 shows statistics on drilling success offshore India. While the rising success rate could be due in part to a growing understanding of the geology of the basin, it is striking how the success rate increased after the two major players in the basin started to make widespread use of seabed logging in 2006.
FRONTIER EXPLORATION
and other available data to develop the best possible earth models. In the last two years, a new paradigm has emerged. A growing number of companies are looking to apply seabed logging earlier in the exploration process in addition to using seabed logging to reduce risk. Sparse, wide-azimuth grids of data that provide regular sampling of large areas can be used to detect significant resistive anomalies. Not all of these anomalies are hydrocarbon-related, but this “scanning” technique is proving successful in identifying the most prospective areas early in the process. This approach not only focuses resources effectively and reduces time to first oil, but it is also an “unbiased” technique. Scanning is just as likely to reveal hydrocarbons in a stratigraphic trap as it is to reveal them in structural traps. Scanning also delivers useful information about the distribution of other non hydrocarbon-related resistors such as volcanics, carbonates, and salt.
IMPROVING DISCOVERY RATES
The most common application of seabed logging is reducing drilling risk. When a potential reservoir is identified on 2-D or 3-D seismic data, seabed logging data can be acquired over the prospect. Anomalously high electrical resistance indicates the possible presence of hydrocarbons. Furthermore, because Archie’s law tells us that high saturation is required to create a significant and measurable change in resistivity, the technique is well-tuned to the detection of commercial saturations – a classic direct hydrocarbon indicator (Figure 3). In the early days, the technique was applied with some success to shallow, highly resistive reservoirs such as the western Troll gas field in the Norwegian North Sea. Seabed logging is now being used to look at deeper and smaller prospects in increasingly complex geologic settings. As applications have become more diverse, the industry has responded by improving every element of the system: instrumentation, survey design, and processing techniques. Today’s seabed-logging measurements are very accurate. Experience shows that in more than 85% of the seabed-logging surveys where it is possible to calibrate against well data, there is a direct link between the seabed-logging measurements and the resistivity well logs. This holds true for both discovery and non-discovery cases. The pre-drilling resistivity earth model should explain any available seabedlogging measurements. If the model does not explain the measurements, the model is probably wrong. If the model does explain the measurements, it has a higher probability of being right.
figure 3. resistivity image overlaid on seismic data
(Data courtesy of Murphy Oil Co.)
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TECHNOLOGY EXPLORATION
WHAT IS ‘STATE OF THE ART’?
Just as seismic exploration started as a 2-D technique and progressed to 3-D, seabed logging is moving quickly to the 3-D era (Figure 2). Real reservoirs are 3-D structures, and they are invariably more complex than is first assumed. The best understanding comes from 3-D sampling. As it did in seismic, 3-D sampling is driving an arms race to increased receiver density. Five years ago, 20 receivers were considered adequate. Today 50 to 70 are required, and the trend continues upward. As higher receiver densities drive quality up and unit costs down, so more seabed-logging applications will emerge. Perhaps the biggest change is in the area of interpretation. In the early days, EM experts were happy to study individual response curves. Today, as Explorationseabed logging seeks out a place in standard exploSuccess Rate Offshore India ration workflows and budgets, it must deliver a product that fits seamlessly into the workflows (and 50.0% workstations) of its users. Full 3-D inversion, allowing delivery of true 3-D resistivity40.0% volumes — together with careful integration with seismic, mag30.0% netotelluric, and other data — is now a major area of focus for all the large seabed-logging players. 20.0%
logging as a significant commercial advantage. The recent emergence of multiclient scanning surveys has further reduced the commercial barriers to wide adoption of seabed logging. Seabed logging will continue to deliver value to an ever widening market.
WHAT DOES THE FUTURE HOLD?
In predicting the future, the most reliable guide is often the past. Seismic data has become ubiquitous in the oil and gas exploration industry. Although 2-D seismic was (and still is) a powerful tool, the great leap forward for the seismic industry was the transition from 2-D to 3-D. It seems likely that the same will be true for seabed logging. It is also possible to predict several trends in the development and application of this technology: I Better measurements will allow us to improve resolution and see deeper into the earth; I More measurements will enhance integrity and reduce the ambiguity of the results; I More diverse measurements, including borehole and permanent seabed measurements, will open up new opportunities, including improved time-lapse techniques; and I Better techniques will spread seabed-logging applications to more complex geologies (shallow water, more complex resistive overburdens, etc.). In areas where seabed logging is effective, discovery rates have increased, and geological risk has been reduced substantially. The technology has now been adopted by a wide range of major international oil companies, independents, and national oil companies. Seabed logging is also creating new opportunities by finding resources that might not have been detected using traditional techniques alone. When integrated within the traditional exploration workflow, the additional information brought by seabed logging means that geoscience, seismic, and drilling resources can be more effectively focused on successful projects. This has enabled a step change in exploration efficiency, productivity, and reduced finding costs per barrel. Today, seabed logging is well established as a prospect risking tool. It has also been shown that seabed logging, when combined with 2-D seismic, can be an effective early exploration lead identification tool. At the same time, intensive work is ongoing to explore the potential to use seabed logging for production monitoring. •••
BENEFICIARIES
10.0%
The early users of seabed logging were major oil 0.0% companies such as Statoil, ExxonMobil, and Shell. 2007 2005 2006 However, 2004 2002 2003 most national oil companies and larger 2001 independents have now tried the technique, and it is no longer the preserve of the major international operators. In fact, there is a new breed of small oil companies that see their experience in Exploration Success Rate Offshore India seabed
50.0% 40.0% 30.0% 20.0% 10.0% 0.0% 2001 2002 2003 2006 2007 2004 2005
Figure 4. Offshore exploration drilling success (India)
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offshore designs
trending toward hybrids
Emerging floating production system units show a remarkable degree of crossbreeding between previously accepted designs that has created entirely new hybrid arrangements.
BY STEPHEN P. NEWELL, ABS any of the floating production concepts that have been introduced recently have taken basic ideas from spars, tension leg platforms (TLPs), and semisubmersibles and combined them in novel configurations. “We see a crossbreeding between traditional floating production installations resulting in entirely new designs,” said Kenneth Richardson, ABS vice president of energy development. “These hybrids are unlike anything we have ever seen. From a class society perspective, the issue is which of our existing rules or risk methodologies should be applied so review of these new structures can move forward offering the same safety equivalencies to more traditional designs.”
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BEHAVES LIKE A SPAR
Technology currently owned by Durward International, a joint venture of Keppel FELS and TexBASS, has created a design that is a cross between a semisubmersible and a truss spar. The MinDOC3 design, which incorporates three generations of optimization from its initial conception, is intended for ATP Oil and Gas’ Mirage field in Mississippi Canyon 941. It is currently under review by ABS. The first iteration of the design received Approval in Principal from ABS in 2001. It is a concept originally conceived by Alden “Doc” Laborde and William Bennett and subsequently developed over a period of eight years by a consortium of industry-leading firms. The MinDOC3’s three vertical columns, arranged in a triangular shape with columns connected to pontoons, at first looks like a semisubmersible. However, engineers analyzing the design say the structure behaves like a spar in terms of stability.
The MonoBR design minimizes heave and pitch, making it more suitable for the application of SCRs.
(Image courtesy of Petrobras)
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DRILLING TECHNOLOGY
“We had to determine what requirements or rules we would apply to this unique design,” said Luiz Feijo, ABS project manager for MinDOC3. “In our preliminary analysis of the hull, we concluded that the in-place stability of the structure indicated it behaves like a spar.” According to Feijo, the position of the center of buoyancy in relation to the center of gravity is the main characteristic of the spar’s geometry and configuration: “With a spar, the center of gravity is well below the center of buoyancy; so this bottom-heavy arrangement prevents the structure from tipping over or capsizing,” he said. In terms of the processing facilities, Feijo said, the T-shaped topsides arrangement of the MinDOC3 is also different from traditional floating production systems. The risers will be tensioned by a hydraulic system rather than air cans or buoyancy cans commonly used on spars.
drilling and production risers. The well deck sits on top of a large buoyancy module that is restrained vertically by risers/tendons affixed to the sea floor. “The buoyancy module is guided between deck and the pontoon base such that the MCF hull can move without imparting high stresses on the riser. The buoyancy module can be thought of as a small tension leg spar vertically restrained by tendons/risers surrounded by a deep draft semisubmersible,” Maher said. Other features incorporated in the MCF design include a mooring system designed for 100-year storm conditions with fast hookup to pre-installed anchors and mooring lines and a large deck able to accommodate drilling and process equipment to meet a wide range of functional reservoir demands. “Primarily, we wanted to develop a design that is capable of drilling and producing in a Gulf of Mexico (GoM) deepwater reservoir at lower risk and lower cost for operators,” Maher said.
MULTICOLUMN FLOATER
ABS has reviewed the conceptual drawings for a multi-column floater (MCF) from AGR Deepwater Development Systems Inc. (AGR DDS). The floater, which is a cross between a cell spar and a semisubmersible, is intended for drilling and production in deepwater, high-pressure, high-temperature fields. AGR DDS President Edward E. Horton III is the original developer of the TLP and the three generations of spars — classic, truss, and cell. “The MCF is, in fact, a combination of a semisubmersible and a spar,” said James V. Maher, chief technology officer, AGR DDS. “The MCF hull is a deep draft semisubmersible with longer columns than the conventional semisubmersibles, and each column is made up of four smaller diameter, closely spaced tubulars like that of the cell spar.” According to AGR, the columns are affixed to the base pontoon, which is normally fully flooded when the MCF is at its operating draft. The hull is towed out to the deck installation site in about 250 ft (76 m) water depth without the deck and ballasted down to a depth where the columns are just above the sea surface. The deck, supported on a deck barge, is floated over the hull between the columns. Then, the hull is deballasted, which raises the deck to its tow-out draft. Another feature incorporated in the MCF design includes a vertically restrained well deck that supports
DESIGN REDUCES RISK
ABS categorizes the deep draft semisubmersible for Chevron’s Blind Faith field in Mississippi Canyon 695 and 696 in the GoM a hybrid because of its hull characteristics, hull subdivision, and ballast system. It ballasts not like a semi but like a spar. “This design is what’s called a ‘passive hull’ because it does not require frequent ballasting operations. Most semis have their pump rooms and sea chests in the pontoons,” Feijo said. For Blind Faith,
(Photo courtesy of Bennett & Associates LLC)
the MinDOC3 is a cross between a semisubmersible and a truss spar.
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TECHNOLOGY EXPLORATION
(Photo courtesy of AGR Deepwater Systems Inc.)
manager for the MonoBR. “Today, we are not surprised by the designs being put forward for classification review. If we are not able to review a design to prescriptive rules, then we take a risk-based approach for determining criteria.” The MonoBR has some characteristics of a spar but a much shallower draft. The design is such that it minimizes heave and pitch, making it more suitable for the application of steel catenary risers (SCRs). With water depths pushing the 10,000-ft (3,048-m) mark in some field developments, industry is concerned with riser fatigue caused by the system’s motions. According to Feijo, the new Petrobras hull design limits or reduces heave, which lessens the fatigue on the SCRs. The FPSOBR was designed for a site specific location offshore Brazil. ABS assessed the strength of the hull by evaluating load components, hull strength, fatigue assessment, and the still water bending moment and loading patterns.
ABS is reviewing the design for the multicolumn floater introduced by AGR Deepwater Development Systems Inc.
HYBRID DESIGNS CHALLENGE REVIEW PROCESS
For ABS, offshore design innovation drives the society to supplement its current rules, develop new rules, or look for new ways to provide design review when there is no in-service experience or historical data to draw upon. “While we still have our prescriptive requirements, today, we often review new and novel concepts by taking a risk-based approach,” Richardson said. A need has arisen for a basic restructuring of the approach toward classification design review because designs for which there is no available in-service history are being developed at an unprecedented rate. Some of the hybrid designs recently underwent design review using the ABS Guidance Notes on Review and Approval of Novel Concepts. Richardson pointed out that often the technology is not new, but the way in which the operator has packaged the technology is different, which requires close review to determine safety equivalencies. Feijo believes innovation for extracting oil and gas in deepwater in both a technically feasible and economical way will continue to spur the advent of new designs. The issue for class societies will be the manner in which they anticipate and develop rules for the next generation of offshore installations to continue to facilitate offshore frontier development. •••
the ballast water comes from pumps attached to the outside of the hull, and the hull tanks are designed independently. The square pontoon shape design is divided into four independent quadrants with no interconnection between quadrants and no ballast pumps inside the pontoons. This ballast system reduces risk from pump or valve failure. The Blind Faith deep draft semisubmersible is the first semi in the GoM with this ballast system.
A ROUND FPSO
Deepwater exploration and production leader Petrobras has developed two new hull production unit concepts, the MonoBR and FPSOBR. The MonoBR concept is a non ship-shaped floating, production, storage, and offloading facility (FPSO) that breaks with the tradition of converting existing tankers into FPSOs. ABS reviewed both designs and provided AIP in 2005. The MonoBR is a short cylindrical mono-column floater that is being considered for offshore Brazil and possibly the GoM. “A round FPSO design was unheard of 10 years ago,” said Feijo, who also serves as ABS project
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BY JUDY MAKSOUD, EXECUTIVE EDITOR
designs keep pace
Violent hurricane season weather conditions have changed design specifications for the Gulf of Mexico.
with Mother Nature
urricane Ivan in 2004 and hurricanes Katrina and Rita in 2005 caused significant damage to oil and gas operations on the outer continental shelf (OCS) of the Gulf of Mexico (GoM). The Minerals Management Service (MMS) reported 123 fixed platforms and one floating platform destroyed by the hurricanes, with many more sustaining considerable damage. A large number of semisubmersible and jackup rigs also required extensive repairs following the storms. In spite of the destruction there were no significant oil spills from wells, and all offshore personnel were evacuated safely. These achievements were the result of extensive planning and preparation overseen by MMS and implemented by the oil and gas industry. As for the damage to facilities, the fact is that hur-
H
ricanes Katarina and Rita exceeded the industry’s 100-year storm design criteria. Storm conditions during these two hurricanes were much more severe than anticipated and were beyond the design specifications for the damaged structures. In the wake of these storms, the MMS and the oil and gas industry joined hands to gather more information on wind, waves, surges, and currents in the GoM to better define 100-year conditions. The objective was to characterize the metocean environment so future structures can be designed to safely weather storms in the Gulf. The American Petroleum Institute (API) defines 100year design criteria as, “a set of environmental conditions that will produce a total force on the platform,
Summary of damage from recent hurricanes in the Gulf of Mexico Hurricane Ivan platforms destroyed platforms severely damaged jackup rigs destroyed rigs severely damaged semisubmersibles and jackups adrift July 2008 | Global Offshore Report | www.EPmag.com 7 20 1 4 5 Hurricane Katrina 46 20 4 9 6 Hurricane Rita 65 32 4 10 13
(Source: US Minerals Management Service)
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<< According to the National Oceanic and Atmospheric Association, Hurricane Katrina will be recorded as the most destructive storm in terms of economic loss. This satellite image shows Katrina on the morning of Monday, Aug. 29, 2005. (Source: NOAA) due to the combination of waves, wind, and current, that has a 1% probability of occurrence per year at that specific location. These criteria are determined based on statistics compiled from all historical hurricanes and other storms in the GoM.” Before the reassessment, 100-year conditions included a wave height of approximately 70 ft (21 m), an 80-knot wind, and a 2.1-knot current for most of the GoM. The new criteria are based on historical weather dating back earlier than those used for previous standards and take into account data gathered during the recent violent storms. The new criteria also address the fact that conditions vary from one part of the Gulf to another. Shortly after Hurricane Ivan swept through the Gulf, the API began developing recommended practices that would make the design requirements for structures working there more stringent. Those efforts resulted in a number of recommended practices and ultimately led to bulletins that would be used to evaluate structures designed for the GoM in terms of stability and robustness. In mid-April 2008, the MMS adopted three API bulletins for hurricane protection to improve survivability of offshore platforms and increase environmental safety. The bulletins include: I Bulletin 2INT-MET – Interim guidance on hurricane conditions in the GoM; I Bulletin 2INT-DG – Interim guidance for the design of offshore structures for hurricane conditions; and I Bulletin 2INT-EX – Interim guidance for assessment of existing offshore structures for hurricane conditions. These bulletins contain engineering design principles and good practices for new platforms and for assessing existing platforms by imposing more exacting design and assessment criteria for both. According to the MMS, the new criteria will increase survivability during hurricane conditions and will result in fewer damaged platforms. Building on improvements made prior to the 2007 hurricane season – such as new guidance documents focusing on enhanced design standards and a Web site dedicated to hurricane information – MMS officially incorporated the API bulletins into a final rule (RIN 1010-AD48) that became effective on May 15, 2008. The MMS believes the new criteria will increase platform survivability during hurricane conditions and will result in fewer damaged platforms. Certainly, the rule sets the bar significantly higher for structures designed to operate in the GoM. “Incorporating these new criteria into the final rule will improve the protection of critical oil and gas infrastructure and allow oil and gas operators to restore
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TECHNOLOGY EXPLORATION
production sooner following an hurricane event,” said MMS Deputy Director Walter Cruickshank. In a bulletin released in May 2008, the MMS publicized its preparation plans for the 2008 hurricane season, which runs from June 1 to Nov. 30. The key goals of the preparations, according to the MMS, are to enhance the nation’s energy security, provide environmental protection, and continue to emphasize personnel safety. MMS officials participated in a media forum with representatives from the US Coast Guard and the API to discuss the new final rules regarding enhanced information on hurricane conditions and
the design of offshore structures. Officials also provided updates at that time on the ongoing recovery efforts from the 2005 hurricane season. “Energy production from the Gulf is vital to our Nation’s energy supply, and it’s imperative that MMS continues our strong emphasis on preparations to reduce the risk of an extended disruption of energy production from the Gulf,” Cruickshank said. “By working with all involved parties, including the US Coast Guard, the API, and the oil and gas industry, MMS remains steadfast in our goal to improve the protection of oil and gas production in the Gulf from disruptions during this hurricane season.” •••
FloaTEC LLC has conducted model testing on one of several floating production concepts the company has developed for use in the Gulf of Mexico.
“
Designing for greater stability
he new metocean criteria for the Gulf of Mexico affect design procedures for future and traditional offshore platform designs in that region,” said John Murray, FloaTEC director of technology development. “FloaTEC is completing the pre-FEED on a version of its extended tension leg platform (ETLP) for deployment in this new environment at a water depth of 5,000 ft (1,524 m).” The ETLP is designed with processing capacity for 120,000 b/d of oil, 110 MMcf/d of gas, 80,000 b/d of water, and 100,000 b/d of water used for injection. It includes an integrated, 2-million-lb rig that can drill to 35,000 ft (10,668 m) total The ETLP underwent model testing to 1,000depth, 18 top-tension risers for drilling and production, and eight steel catenary year hurricane conditions at the Offshore risers for production, injection, and export. Technology Research Center at Texas A&M The structure consists of four columns measuring 210 ft (64 m) high and 76 ft University. (Photo courtesy of FloaTEC LLC) (23 m) wide that are connected under water by four pontoons. The distance between the columns is 220 ft (67 m). Pontoon extensions, which increase the restoring effect of the tendons while reducing the column spacing, move the tendon connection point outboard of the columns. According to Murray, the columns are circular for structural efficiency and to minimize environmental loading. The structure is moored using 12 tendons – three tendons per corner, connected 18 ft (5 m) above the keel. The ETLP, which has 95,453-short-ton (86,594-metric-ton) displacement, is designed with a still water air gap of 106 ft (32 m), an installed draft of 113 ft (34 m), and a wet tow draft of 35 to 40 ft (11 to 12 m). The new design underwent model testing at a scale of 1:92 under the new GoM metocean criteria [API, 2007] at the Offshore Technology Research Center at Texas A&M University. The scaled-down glass fiber hull model was moored in the wave basin to measure its performance in 1,000-year hurricane conditions. “The test program included wind tunnel and wave basin tests in wind, waves, and current,” Murray said. Simulated conditions generated 114.5-ft (35-m) maximum wave height, 117-knot hourly wind speed, and 4.4-knot current speed at the surface. “Results from the model testing indicate the ETLP design meets all of the criteria for the intact condition in 100-year hurricane post-Katrina conditions,” Murray said. •••
T
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BY MATTHEW DONOVAN, ODS-PETRODATA
offshore rig market
boom continues
The energy industry has concluded that the days of easy oil are over.
H
$600,000 $500,000
igh oil prices are forcing companies to look for resources in previously inaccessible areas to boost production. Mature regions like the North Sea and Gulf of Mexico (GoM) are still producing, but as demand grows, deepwater becomes more important.
INDUSTRY RESPONDS
Owners of mobile offshore drilling units are taking advantage of market conditions. Plans are in place to build 78 semisubmersibles and drillships, with 73
Source: ODS-Petrodata Consulting & Research
Day Rate US $
GOM Jackup $400,000 N Sea Jackup WW Mid-Water Semi $300,000 WW Deepwater Floater
of them capable of drilling in 3,000 ft (914 m) water depth or more. Strong demand for deepwater drilling rigs has created a global supply shortfall. While many of the deepwater rigs under construction in the world’s shipyards were ordered on speculation, all are expected to have firm contract commitments before delivery. The rig shortage has forced some operators to schedule drilling programs around rig availability rather than a preferred timetable. Deep water is not the only driver behind construction. Worldwide, 82 jackups drilling units are on order, planned, or under construction. Because conditions in the jackup market are different from those in the deepwater rig market, however, the flood of new jackups may result in a temporary softening in jackup fleet utilization and day rates. The cost of offshore rigs on order or under construction as of late May 2008 exceeds US $56 billion.
DRILLSHIPS
In total, 34 drillships are planned, on order, or under construction. This number outstrips the entire global fleet (26). The growing market for drillships can be attributed to their mobility and their suitability for deepwater and ultra-deepwater conditions. Today, seven drillships are working offshore Brazil for Petrobras. Five are in the Indian Ocean on contract with ONGC and Reliance. Four are drilling in the GoM. The remaining nine are working offshore West Africa. Eight of the drillships under construction will head to the US GoM once they are completed. Reliance
$200,000
$100,000
$0
Ja n01 Ju l-0 1 Ja n02 Ju l-0 2 Ja n03 Ju l-0 3 Ja n04 Ju l-0 4 Ja n05 Ju l-0 5 Ja n06 Ju l-0 6 Ja n07 Ju l-0 7 Ja n08
average modu day rates 2001 to present, selected rig classes. Short supply and high demand have pushed up day rates.
(charts courtesy of ods-petrobras)
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DRILLING TECHNOLOGY
Supply/Demand --No. of Rigs Supply/Demand No. of Rigs
150 150
60% 60%
SEMISUBMERSIBLES
Thirty-nine of the 44 semis planned, on order, or under construction are rated for water depths of 3,000 ft (914 m) and greater. There are 142 semis drilling worldwide of 168 existing rigs. Today, there are 81 deepwater semis. Strong markets include the US GoM, where 25 semis are drilling, South America with 26, and the Indian Ocean, where 45 semis are at work. Thirtysix semis are active in Northwestern Europe.
100 100
40% 40%
50 50 Supply Supply 0 0
AAp pr r -00 88 M M aay y- 008 8 JJu unn -00 88 JJu ul l -00 88 AAu ugg -00 88 SSe epp -00 88 O O cct t-00 88 N N oov v- 008 8 D D eec c- 008 8 JJa ann -00 99 FFe ebb -00 99 M M aar r-00 99
20% 20% Demand Demand Fleet Utilization Fleet Utilization 0% 0%
Worldwide floating rig demand forecast
JACKUPS
Of the 424 global jackup fleet, 358 are under contract, twenty are stacked, and the remainder is en route between markets, in shipyards, or otherwise not available for work. Nineteen jackups are drilling offshore China, with many of those on order destined for the region. China Oilfield Services Ltd. has seven jackup rigs on order or under construction, while China National Offshore Engineering Co. is awaiting the completion of four others. The US GoM continues to be a major market for jackups despite the recent slump in the region’s rig market. Of the 80 jackups in the region, 59 are under contract and drilling. The move from the Gulf’s shallow waters over the past decade by major oil companies has seen the rig market change. Many rigs have left the area, and some drilling contractors have withdrawn from the market completely. Transocean Inc. recently sold three jackup rigs to Hercules Offshore, marking its exit from the shallow waters of the GoM. Hercules Offshore moved the rigs away from the Gulf, contracting them to Saudi Aramco. Hercules Offshore’s rigs join the 87 jackups drilling in the Middle East on projects offshore the United Arab Emirates, Qatar, Egypt, and Oman, and throughout the Persian Gulf. Twenty jackup rigs are drilling offshore the United Kingdom and Norway, working on wells in the North Sea. •••
n late May, Transocean Inc. set a world record with the jackup GSF Rig 127 for the longest extended-reach well ever drilled at 40,320 ft (12,289 m) measured depth (MD) with a 35,770-ft (10,902-m) horizontal section. The new record of 7.6 miles (12.2 km) is also the first well in the history of offshore drilling that exceeds 40,000 ft (12,191 m). The horizontal section was drilled in two runs with Schlumberger’s PowerDrive X5 and PowerDrive Xceed rotary steerable systems (RSSs). The TeleScope high-speed telemetry-while-drilling system transmitted geosteering information in real time as well as continuous measurement of parameters that affect drilling efficiency. The system also ensured that downlinking commands were received by the bottomhole assembly all the way to total depth. Totally batteryless logging-while-drilling (LWD) triple-combo equipment was used for the first time on this run. The equipment was powered by a turbine generator driven by drilling fluid circulation. “Extended reach drilling is a natural application of our high-performance drilling technology,” said Mike Williams, Schlumberger global sales manager, Drilling & Measurements. “This helps our customers access more reservoir volumes from a single drill site, reducing overall costs and environmental impact.” The record-setting well, BD-04A, is in the Al-Shaheen field offshore Qatar. “Everyone involved deserves congratulations for coming together and through great planning and teamwork managing the challenges on this well in an incident-free manner,” said Jim Granger, performance rig manager. •
I
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(Photo courtesy of Transocean)
Record Reach
Fleet Utilization Fleet Utilization
has snapped up at least three newbuild drillships for prospects in the Indian Ocean, and Total has contracted two new drillships for West Africa. Most of these vessels are being built in South Korean shipyards because these yards have experience building hulls and mating them to the topsides.
250 250
Source: ODS-Petrodata Source: ODS-Petrodata
100% 100%
200 200 -
80% 80%
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innovations inproduction floating
BY JUDY MAKSOUD, EXECUTIVE EDITOR
Tens of billions of dollars are expected to go toward deepwater drilling and production over the next few years, and the industry is developing new systems to carry out an enormous amount of deepwater work.
loating production systems have gone through significant changes over the past two decades as drilling and production have moved into deeper water. Semisubmersibles have grown in size and capability, and spars have become viable deepwater production systems outside the Gulf of Mexico (GoM). Today, there are even more changes in the works.
F
DRY TREE DESIGNS
One of the innovations for semisubmersibles is the move toward dry trees. FloaTEC LLC has developed two dry tree designs, the truss semisubmersible (Truss Semi) and the E SEMI II (E SEMI). The two semis are designed using heave plates that stabilize the structures. The E SEMI II has a single heave plate that is lowered into position when the hull is at the installation site. Installation is reversible and allows the vessel to be returned to port for outfitting and/or redeployment. Intended for installations of longer duration, the Truss Semi accommodates longer trusses. It offers more flexibility in adjusting the relative heights of the heave plates to minimize the heave motions. FloaTEC has sized both designs and has analyzed their performance for the post-Katrina 100-year hurricane environment in the GoM. SBM Atlantia’s FourStar tension leg platform (TLP) is another design that incorporates a dry tree. The FourStar is based on the SeaStar concept, which has been in use for several decades. The FourStar differs from the company’s original TLP concept in its ability to handle larger payloads. The primary difference between the new FourStar TLP and the SeaStar is that the FourStar’s columns are battered toward the center of the platform, which allows the hull footprint to be larger. The increased footprint size places the tendon porches further from the center of the platform, which maximizes the effective arm of the tendons, making the tendon system smaller and more economical.
SPAR TECHNOLOGY
Technip has designed a three-deck spar with a drill set on top. (Image courtesy of Technip)
Technip’s new spar is outfitted as a drilling rig. A traditional spar does not have enough real estate to accommodate a drill set, so Technip took its
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PRODUCTION TECHNOLOGY
design in a different direction. The new unit is a three-deck spar with a drill set on top. The drill floor is 50 ft (15 m) lower in elevation than the traditional spar’s top deck, which brings down the vertical center of gravity, allowing for the installation of a 200ft by 90-ft (61-m by 27-m) pipe rack with a 2,000-metric-ton capacity for tubular storage. Technip sized a 5,000-metric-ton skiddable drill set for the new spar, which will have 2-million-pound hook load, 2.5-million-lb setback load, and will carry more than 60,000 ft (18,288 m) of tubulars. The well bay design includes a permanently installed drilling riser that doesn’t have to be pulled to carry out grassroots drilling. The riser can be moved offline and parked in such a case because there is a special slot from which the unit can perform grassroots drilling. Where the hull in a traditional spar is empty, the drilling and production spar houses circular bulk storage and mud tanks. The mud system consists of four 2,200-hp pumps with 7,500-psi capability, which is necessary for deepwater subsalt drilling. The drilling and production spar weighs approximately 5,000 metric tons and has an operational weight of 30,000 to 40,000 metric tons. Versabuoy International has also designed a floater that uses spar concepts. The new deepwater production platform system consists of articulating spars. Connecting the platforms together creates what Versabuoy calls a floating, moveable land mass that is fairly inexpensive to construct and mobilize. The length of the spar keeps heave to a minimum, while the articulating joint absorbs wave energy, allowing the platform to remain level. Model tests for the platform have proven that the Versabuoy System is stable in harsh marine environments, including hurricanes, which makes it a viable option for the GoM. AGR Deepwater Development Systems Inc. (AGR DDS) has placed a third spar idea on the table. Introduced by Edward Horton III, the drilling and production multicolumn floater (MCF) is a cross between a cell spar and a semisubmersible. The MCF hull is a deep draft semisubmersible with longer columns than those on conventional semisubmersibles. Each column is made up of four smaller diameter, closely spaced tubulars like that of the cell
spar. The columns are attached to the base pontoon. The MCF has a vertically restrained well deck which supports drilling and production risers — that sits on top of a large buoyancy module. The system has a mooring system designed for 100-year storm conditions, with fast hookup to pre-installed anchors and mooring lines, and a large deck that can accommodate drilling and processing. Durward International, a joint venture between Keppel FELS and TexBASS, has created yet another floater, the Minimum Deepwater Operating Concept (MinDOC). Though the MinDOC resembles a semisubmersible, it behaves more like a spar in terms of stability. The position of the center of buoyancy in relation to the center of gravity is the main characteristic of the spar’s geometry and configuration. Instead of a single cylindrical column, the MinDOC design features three narrow caissons in a triangular arrangement joined at regular intervals. This design minimizes motions and increases the vessel’s stability, improving as the topsides payload increases. The “T” shape of the MinDOC topsides makes the unit different in appearance from traditional floating production systems. Another interesting difference in the design is that the risers will be tensioned by a hydraulic system rather than the air cans or buoyancy cans typically used on spars. Though the MinDOC can work in varying water depths, it is most likely to be employed in water
(Image courtesy of FloaTEC LLC)
The E SEMI II will give operators more options for dry tree drilling and production in ultra-deep water. www.EPmag.com | Global Offshore Report | July 2008
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TECHNOLOGY DRILLING
Helix Energy Solutions’ Producer I is expected to produce for five to 10 years in the Gulf of Mexico. (Image courtesy of
Helix Energy Solutions)
OPE’s SSP features a spherical-shaped hull with a center column that provides stability in rough seas. (Image courtesy of OPE)
between 3,000 and 10,000 ft (914 m and 1,524 m) deep because of the competitive advantages offered in greater water depths.
FPSOS
Last October, Sevan Marine’s cylindrical FPSO, Sevan Piranema, began oil production on the Piranema field in ultra-deepwater offshore Brazil. The Sevan Piranema is the world’s first-shaped FPSO. According to developers, the cylindrical design provides improved motions, higher stability reserves, and higher deck load capacity than conventional units. The FPSO has an oil storage capacity of 300,000 bbl and is equipped with an oil processing capacity of 30,000 b/d and gas compression capacity of 3.6 million cu m/d. Orders are in place for four additional Sevan units, of which three are production units and one a drilling unit. The three FPSOs will be installed in the North Sea. The Sevan Driller will work in the GoM under a six-year contract with Petrobras America Inc. OPE Inc. has pioneered yet another hull form with its spherical Satellite Services Platform (SSP). The SSP is a patented spherical-shaped floating vessel with a center column. Engineers at OPE contend that the design provides measurable advantages over shipshaped vessels and traditional platforms. Stability in rough seas is one of the selling points
of the new design. Tests performed on the model SSP320 at Marin’s basin facilities in the Netherlands resulted in less than 4° significant pitch/roll in Katrina-type storm conditions and less than 0.07 g heave acceleration in a one-year GoM winter storm, OPE says. The model has a 1.25 million bbl oil storage capacity and can produce 80,000 b/d. Though there are no SSPs on the market at present, OPE expects to award initial construction contracts by 3Q 2008. Meanwhile, Helix Energy Solutions is about to launch the first ship-shaped floating production unit (FPU) in the GoM, the Producer I. The vessel will be fitted with 3,500 tons (3,180 metric tons) of topside production modules capable of handling 45,000 b/d of oil, 70 MMcf/d of gas, and 50,000 b/d of water. Because the topsides modules are removable, production equipment can be taken off so the vessel can be converted for other service work, such as pipelaying, if that is a more economical option when the initial production project is completed. The Producer I is expected to produce for five to 10 years from the Phoenix-area fields (formerly called the Typhoon field) in blocks 236 and 237 in the Green Canyon area of the Gulf. The FPU, which has an estimated production life of 20 years, will be able to move to another deepwater field when the Phoenix project is concluded. •••
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SUBSEA SOLUTIONS
stretch the imagination
With significant growth predicted for subsea investment, innovative minds are hard at work, and the prize is easily worth the price.
lobal annual investment in subsea technology is expected to rise to US $45 billion by 2012. A lot is at stake. Vast offshore discoveries are waiting to be developed, but there are problems. Financial managers are concerned with the huge upfront investments that must be made before the first barrel or cubic foot of production hits the sales line. Production managers know that there are a lot of risks between the reservoir and the export line. Together, they seek the best solution, one that will provide a steady supply of hydrocarbons with minimal intervention for the life of the reservoir, and one that will do so as economically as possible. About half of the investment will go to pipelines, the vital links that transport production from wellhead to gathering station to production facility as well as the export lines that link to the markets. Although pipelines may seem like rather mature technology with little upside potential for improvement, that is not the case. Particularly in subsea, flow assurance techniques and technologies are being developed and implemented to keep the lines free of asphaltenes, hydrates, and wax buildups. And, increasingly, long subsea lines require booster stations to keep the production flowing. Notwithstanding the added cost and difficulty, engineering studies indicate that the closer production processing activities are to the wellhead the more effective they are, so modules in the production stream traditionally located on dry land or
BY DICK GHISELIN, CONTRIBUTING EDITOR
G
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PRODUCTION TECHNOLOGY
<< Figure 1: Subsea compression module
located in test pit (Image courtesy of Aker Solutions)
aboard a platform or production vessel are taking the plunge to the seabed. Companies are taking a systematic approach to solving subsea production and processing problems. An example is a recent release by Aker Solutions. The growth of the hub-and-spoke subsea production technique calls for innovative ways to efficiently move production from the wellheads to the hub in increasingly deeper waters, as well as provide support for both seawater and gas injection schemes. Gas creates its own set of problems. Aker Solutions has taken the initiative to develop a subsea gas compressor to add to its subsea booster family. According to the company, the huge Ormen Lange field ranks as the most ambitious potential application for subsea compression. To that end, a modular compressor pilot unit is being built. Upon its completion, anticipated for 2010, the 700-metric-ton unit will be disassembled and shipped to the Nyhamna terminus of the Ormen Lange subsea pipeline, where it will receive extensive environmental testing in a seawater-filled pit for two years (Figure 1). With success, a commercial full-size unit consisting of four compressor trains capable of moving both gas and condensate will be built and installed on the seabed 75 mi (120 km) offshore.
that included a 6-month subsea evaluation on BP’s North Sea Magnus field. According to the company, the CameronDC system can operate successfully up to 120 mi (192 km) from its production facility and is scalable to more that 15,000 ft (4,572 m) water depth. Design service life is at least 20 years. An innovative electric-actuated tree has been announced by FMC. It has the advantage of being retrofittable to existing trees and uses rechargeable Lithium-ion batteries to power actuators that operate the valves. As a result, the system features relatively low power consumption. Actuators and control modules are redundant and retrievable, and the system is designed for a service depth of 9,840 ft (3,000 m). A key feature of the system is its fail-safe emergency shutdown system. In the event of a power failure, the actuators bleed off hydraulics to the subsurface safety valve allowing it to close.
Figure 2: Subsea multiphase flowmeter module can serve up to eight North Sea wells in two fields.
(Photo courtesy of Framo Engineering)
POWERED TREES PROLIFERATE
Earlier this year, Cameron announced the successful installation of its CameronDC all electric subsea production system on Total’s K5F development in the Dutch sector of the North Sea. The tree is the first of a family of subsea systems that will ultimately include boosting, separation, and reinjection. The installation followed extensive design and testing
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TECHNOLOGY PRODUCTION
A Trio of Subsea Solutions
roviding technology and equipment to assure successful, efficient subsea oil and gas production in all water depths, Aker Solutions’ technologies implemented within the last 24 months include booster pumps to overcome problems such as producing low-pressure reservoirs in deep and ultra-deep water and long tiebacks of weighty umbilicals required because of lack of infrastructure near new production wells. Subsea boosting technology is being implemented in response to two challenges to operators: extending the life of their reservoirs as well as managing deepwater developments and long step-outs. Statoil’s Tyrihans project in the North Sea will rely on an Aker Solutions SeaBooster system, expected to be online in 2009. Two seabed pumps will supply water through an injection well into the hydrocarbon reservoir to maintain reservoir pressure and enhance oil recovery. Located in 864 ft (270 m) water depth, the Tyrihans field is a small satellite producing back to the Kristin platform. The Tyrihans seawater injection system will use subsea transformers to optimize power transmission efficiency and will be the highest-capacity subsea raw seawater injection system ever developed. A 10% increase in oil production is expected when the pumps are brought online. MultiBooster pumps have been proving their mettle in the Gulf of Mexico (GoM) after being deployed last fall and successfully operated in the King field for BP. Two of these pumps broke world records for pump operation in water depths in excess of 5,440 ft (1,700 m) and a step-out of more than 18.1 mi (29 km) from the platform. The MultiBooster subsea system increases oil production and recovery rates, extends the useful life of fields, and enables longer step-out distances between subsea assets and host facilities by adding energy to the wellstream. Umbilical deliveries grow due to breakthrough technology introduced within the last year. Aker Solutions will deliver about 230,000 ft (70 km) of high-voltage power cables, as well as static and dynamic steel tube umbilicals, for Petrobras’ Cascade and Chinook subsea development in the GoM. The fields are in the Walker Ridge area, roughly 165 mi (103 km) south of the Louisiana coast. Both the high-voltage power cables and the umbilicals will be installed in water depths to 8,800 ft (2,750 m). The umbilicals will be made using the company’s patented carbon fiber rod technology, which produces dynamic umbilicals of lighter weight that are highly flexible and have good mechanical characteristics. Such umbilicals can withstand the environmental challenges in deepwater GoM locations. •
MULTIPHASE SOLUTIONS BENEFIT SUBSEA
Several initiatives take advantage of complementary technologies to solve subsea production problems. As subsea solutions emerge, it becomes necessary to adapt technologies traditionally employed on the surface to the subsea environment. Flowmetering equipment must be marinized, which includes extending its ability to operate unattended for up to 20 years. Subsea metering solutions are being sought by Anadarko for its giant Independence Hub production facility. This is not a trivial challenge and must be applied to single-phase and multiphase metering equipment (Figure 2). Total has announced plans to develop subsea gas/liquid separation, a world’s first says the company, for its Girassol and Dalia developments offshore West Africa. Challenges include production of two very different oils, one of 35° to 38° API, the other of 17° to 22° API. Engineers have determined that problems can be mitigated somewhat by placing the separators as close to the wellheads as possible to take advantage of the natural production temperature of the hydrocarbon. The warmer it is, the easier it is to separate. The introduction of mono-ethylene glycol to keep gas lines flowing can actually impede flow if it accumulates in low spots in the lines. Seabed compression has a high potential to alleviate this problem, according to engineers at Det Norske Veritas. With such myriad problems to solve, Deepsea Engineering and Management Inc. suggests development of computer models for each situation. The idea is that alternatives can be “game-played” in the models to see which represents the best solution. Absent such a strategy, it would be possible for separate developments to have counter-acting effects when they were integrated into the field production system. From all appearances, there are plenty of projects in which to invest the billions allocated for subsea solutions worldwide – and plenty of applications needing them. •••
P
ALTHOUGH PIPELINES MAY SEEM LIKE RATHER MATURE TECHNOLOGY with little upside
potential for improvement, that is not the case. Particularly in subsea , flow assurance techniques and technologies are being developed and implemented to keep the lines free of asphaltenes, hydrates, and wax buildups.
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the rising tide
BY DICK GHISELIN, CONTRIBUTING EDITOR s the saying goes, “A chain is only as strong as its weakest link.” In the world of offshore drilling and production, a very important link spans the distance between the well and the rig or production facility. The riser is the subject of much engineering thought, careful design, and rigorous testing these days as the frontiers of drilling production extend into deeper water. It’s easy to imagine why so much thought is going into risers. If a well fails, it can be worked over; if a rig or production facility fails, it can be repaired, but a riser failure? Well, that’s unthinkable. The recent spate of major hurricanes has spurred considerable activity in riser innovation. The current thinking is to achieve at least two objectives: separate the movement of the floating unit (rig or production vessel) from the steel riser, and enable the floating unit to make a quick, safe exit should a storm threaten. Obviously, the task is quite different for drilling units than for production units, but the objectives are the same. The main difference is that the drilling riser is meant to be broken down each time the rig relocates, so it is in use for relatively short periods, then is recovered and inspected before it is deployed again. The production riser is expected to remain in place for the life of the field, which is typically 20 years or more.
of riser technology
Deep drilling and production call for deep thinking to design the risers needed to span the distance between seabed and surface — innovations abound.
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THE LATEST AND GREATEST
Petrobras has taken the lead in deepwater riser design. Under a deepwater initiative titled Procap 3000, the first of four deepwater designs has been implemented. A free-standing 18-in. diameter hybrid riser has been installed on Brazil’s Roncador field in the Campos Basin. Serving the P-52 semisubmersible floating production unit, the riser spans about 5,576 ft (1700 m) of water between a base foundation set in the seabed and a buoyancy can that floats about 328 ft (100 m) below the surface, well beneath any wave action. At the bottom, a rigid jumper connects the riser base to the subsea pipeline export terminal (PLET), while at the top, a flexible jumper runs between the hangoff slot on the P-52 to a gooseneck at the top of the steel riser. A subsea pipeline runs 35 mi (56 km) to jacket platform PRA1, located on the continental shelf in 328 ft (100 m)
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PRODUCTION TECHNOLOGY
of water (Figure 1). The buoyancy can is compartmentalized, and buoyancy force can be adjusted by ballasting different compartments with either seawater or nitrogen to keep the steel riser at its designed tension. The nitrogen is required because the buoyancy can is not a pressure vessel, so a means is needed to balance internal pressure against the hydrostatic ocean pressure at 328 ft (100 m). There is a spare compartment in case one compartment springs a leak, and the can is instrumented, so any leaks will be detected immediately and an alarm sounded in the P-52 control room. The can is attached to the upper riser terminal and gooseneck by a chain to keep any lateral force from meandering sea currents from translating to the riser. Chain tension is continuously monitored. The hybrid design is also suitable for intake lines bringing production to the P-52, but in that case, the vertical steel risers would be smaller, bundled pipes. In actual practice, P-52 is connected to its subsea facilities by 44 risers and 23 umbilicals. The P-52 gathering system comprises 33 wet tree wells with production and water injection flowlines connected directly to the vessel, while gas lift flowlines are attached to three subsea manifolds that are linked to the facility by a gas lift ring pipeline. During the design phase, which took the better part of five years, it was necessary to alter the scope to include innovations proven in other fields around the world. With remarkable open-mindedness, the company gave careful consideration to each. These included steel catenary risers (SCR), flexible risers, and free-standing steel hybrid designs. The final design selected flexible pipe for all intake and injection risers and the free-standing hybrid riser for the single export line. The SCR designs were completed, but held as a fallback option in case of problems with the flexible pipes.
FPSO
TURRET BUOY BUOYANCY TANK
FLEXIBLE JUMPER
RISER
FLOWLINE JUMPER ANCHOR BASE
Figure 1. The P-52’s free-standing hybrid riser links to a flexible jumper and a 35-mi (56-km) export pipeline to bring production ashore. (Source: OTC
19336)
ELSEWHERE, HYBRIDS TAKE HOLD
One of the advantages of the free-standing hybrid riser tower (HRT) design is its scalability. Several HRTs can be arrayed in a circle around a single floating production vessel or turret, each supporting bundles of riser pipes is desired. Production flowlines, injection and gas lift lines as well as export flowlines can be accommodated. HRTs can be found offshore West Africa and in the
Gulf of Mexico (GoM). At the moment, the spotlight is falling on Petrobras’ intention to implement the first floating, production, storage, and offloading (FPSO) installation in the Gulf. With a design that operates in 7,000 ft (2,134 m) of water including warding off the effects of a strong loop current, the Petrobras plan will be truly unique. In deference to the threat of hurricanes, the plan calls for the flexible jumper from the top of the HRT to terminate in a submersible turret buoy that is independently moored. In operation, the turret buoy nestles in a specially designed circular moonpool in the hull of the FPSO, permitting the vessel to weathervane 360°. Should a storm approach, the turret can be released so that it sinks to its point of neutral buoyancy, about 165 ft (50 m) below the sea surface, and far below any anticipated wave action. Once disconnected, the FPSO can sail out of harm’s way. After the storm has passed, the ship can locate the moored turret and deballast it so it floats back up into its moonpool socket for reconnection. With the exception of the turret buoy, the GoM HRT is quite similar to the export HRT used on the P-52 offshore Brazil. A single turret buoy is capable of handling flexible jumpers from four HRTs as well as associated control and power umbilicals.
A DIFFERENT APPROACH
At the recent Offshore Technology Conference (OTC), SBM revealed its MoorSpar design. The system is lesswww.EPmag.com | Global Offshore Report | July 2008
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Figure 2. The first FPSO implemented in the Gulf of Mexico plans to use four free-standing hybrid risers linked to a submersible turret buoy. (Source: OTC 19679)
intrusive than the Petrobras design because it does not require an FPSO with a special moon pool, but still offers the disconnectability features required for hurricane avoidance. In the SBM design, a moored truss spar is used as the upper terminus for SCRs. The spar is scalable to accept as many SCRs as the offloading vessel can accommodate and is rated to 10,000 ft (3,049 m) of water. On the top of the MoorSpar is a movable gimbal table that allows the FPSO to weathervane 360°. An articulated arm extends from the bow of the FPSO and is linked to a main roller bearing below the gimbal table. According to SBM, the arrangement allows the vessel to heave, pitch, and roll independently of the spar. Flowlines in the arm are connected by full-motion swivel fittings. Flexible jumpers are not used, giving the Moor Spar high-pressure, high-temperature (HPHT) capability. In the event of a storm, the articulated arm disconnects from the gimbal table and swings out of the way, allowing the vessel to depart. The MoorSpar has a very small cross section exposed to wind and wave and is designed to ride out the storm as is.
cross sections, vied with helical-vaned strakes. The debate has waxed and waned since the 1960s. Helical strakes had a head start, because they had already been proven effective in suppressing windinduced vibration in smokestacks. Various designs and sizes of strakes and fairings have been tested. For the purposes of understanding, standard strake and fairing designs were established and tested; thus any new designs could be compared to the performance norms of the standards. One condition affecting VIV is surface roughness. Not such a problem in wind tests, roughness can become a major problem in offshore applications. Marine growths can adhere to the member, which can change its apparent roughness considerably. While several valid conclusions were reached, there was no apparent winner. The debate continues. Interaction of SCRs with the seabed was also the subject of several papers. Various soil types were investigated to see which contributes to the most riser fatigue at the touchdown point. In addition, finite element analysis was used to better understand the riser/seabed interaction as the upper end is affected by wave action. It was concluded that the SCR/soil interaction could be adequately modeled. Thus the effects could be characterized for various types of seabeds.
DRILLING RISER LIFE EXTENSION
Oil States introduced its latest version of the fieldproven Drilling Riser FlexJoints (Figure 2). The company has been challenged to keep pace with steadily increasing requirements as drilling descended into deeper waters, HPHT conditions increased, and the presence of corrosives became more prevalent. The result is a system that maintains hydraulic integrity while reducing the bending stress on the drilling riser or reactive stress on the seabed blowout preventer. In addition, it provides omni-directional flexing capability with low angular stiffness even when under extreme axial tension or internal pressure. Lastly, the design dampens vibration and accommodates shock loading. Three versions of the FlexJoint are available: the subsea type that connects the riser to the lower marine riser package, an intermediate type suitable for insertion anywhere riser stress relief is needed, and the diverter type that attaches immediately below the diverter at surface. •••
ON THE DEBATE FLOOR
Two issues remained in active debate at the OTC: Vortex-induced vibration (VIV) and SCR seabed interaction. A number of papers presented results of tests of various configurations of VIV-suppressant devices. Clamp-on fairings, with their characteristic teardrop
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