Offshore technology development will focus on smaller footprints and more efficient designs.

The oil industry continues to focus on offshore exploration, drilling and development as the key to unlocking the Earth's largest remaining hydrocarbon reserves. But the difficulty of operating in water rather than on land continues to present hurdles. With offshore development projects costing billions of dollars, research focuses on making these operations as efficient as possible, often in extremely innovative ways.
Searching for a better process
Newly created ChevronTexaco, BP with ABB and Kværner have just finished a collaborative study on seafloor processing, and together they have agreed on a second-phase program to investigate the concept further.
Targeting deepwater reserves - depths greater than 5,000 ft (1,500 m) - the research has proven that seafloor processing can unlock oil and gas fields in deep water. The ultimate goal is to eliminate the footprint of surface facilities entirely.
Technology gaps have been identified, and the next step is moving toward a full-fledged seafloor processing concept building on experience with the Subsis (subsea separation and injection system) technology.
ABB tested its Subsis seafloor processing equipment on Norsk Hydro's Troll C development, which has been operating in a water depth of 1,150 ft (350 m) in Norway. The success of that trial prompted BP and ChevronTexaco to take it further.
In partnership with ABB and Kværner, the two operators plan to look for a suitable field discovery on which a full-scale model of the Troll C pilot system can be used.
Deployment of Subsis on Troll C is said to have resulted in a production increase of 5,000 b/d of oil since 50% of the produced water is reinjected.
Furthermore, tests of the produced water from Subsis have shown it is well within environmental legislation requirements.
One element of Subsis is the "semi-cyclonic" inlet, which allows simplification of the main separator internals. A Mecon electric motor, which powers the separator, also passed reliability trials on Troll C after initial problems were ironed out and an oil-water sensor within the equipment proved satisfactory.
Three technology teams in Norway, the United Kingdom and the United States will look at equipment standardization, modularization (allowing easy repair and replacement) and remote operation issues in order to take the concept forward.
However, several technology areas must be addressed in the next phase of research. These include oil-gas-water separation and oil-water metering, instrumentation and controls for process monitoring, reliability, flow conditioning, process modeling, solids management, pumping and subsea power distribution.
If these can be overcome, the industry will be on the road toward an operating environment free of surface facilities and the attendant capital and maintenance costs and risks they entail.
Stingray set for sea debut
A generation of children grew up watching a British TV series called "Stingray," which was about a fictitious submarine. But its namesake is real, and it is set to become a power source for the future.
Engineering Business (EB) in Northumberland, England, which 20 years ago became involved in the oil and gas business through experience in design, construction and operation of pipeline plowing and burial, intends to trial its wave-power generator by the summer of 2002.
Stingray transforms kinetic energy from moving water into hydraulic power, which turns a generator by means of a hydraulic motor. EB believes it is possible to use a direct linear generator, and this technology is under development at Durham University in the United Kingdom.
Designs for Stingray indicate vanes 6 ft (1.8 m) deep and 33 ft (10 m) wide, with a 26-ft (8-m) support frame below.
EB unveiled its product at the Institute of Marine Engineers Marec 2001 conference in the United Kingdom earlier this year in a paper by Dr. Tony Trapp and Mike Watchorn.
"The Stingray generator consists of a parallel linkage holding a stack of large hydroplanes, typically three," they explained. "The hydroplanes have their attack angle relative to the approaching water stream varied by a simple cylinder and louver mechanism. The combination of lift and drag forces causes the arm to oscillate vertically (or horizontally) over a range of about 39 ft (12 m). A hydraulic cylinder attached to the main arm is forced to alternately extend and retract, producing high-pressure oil to be pumped to a motor/generator set. The entire structure remains fully submerged and may be rock-bolted rigidly onto the river/sea bed. To generate 150 kW from a current speed of 3 knots requires a channel area of about 1,937 sq ft (180 sq m)."
The significance of Stingray, from a UK perspective, and its relevance to the oil and gas sector is twofold. First, it represents a diversification of engineering skill and technology from the marine oil and gas industry to a new and growing sector, the renewable energy market.
Second, that renewable energy market is becoming more valuable, a point underlined by UK Energy Minister Brian Wilson when he opened a wave power project off the Isle of Islay in Scotland.
"This development means wave power will be able to contribute to the government's target of producing 10% of electricity from renewable energy by 2010," the minister said. "The government is expecting to create a US $1.4 billion (£1 billion) market for renewable energy by 2010. Direct investment of over $350 million (£250 million) over the next 3 years will contribute toward this."
Deepwater anchors scrutinized
Among the variety of methods available to drill for and produce oil and gas in deep water, one requirement remains the same - find some way to anchor these gizmos to the seafloor so the whole apparatus doesn't float away with the currents.
To that end, Texas A&M University's Offshore Technology Research Center has embarked on a study to:
• determine the best available practices for analysis and design of anchoring systems;
• characterize the deepwater environments and site investigation strategies relevant to deepwater anchor designs; and
• improve the accuracy and precision of installation and capacity predictions through theoretical and experimental studies.
Two types of anchoring systems are available: suction caisson anchors and vertically loaded anchors. The latter includes drag embedment anchors and suction-embedded plate anchors (SEPLAs). Despite numerous applications of these anchoring systems, guidelines for installation are virtually nonexistent. The study hopes to update existing American Petroleum Institute documents with regard to installation and extreme environmental loading.
Much of the work surrounding these anchoring systems revolves around the soil conditions in which they're placed. The study area, which includes the continental slope offshore Texas and Louisiana in the US Gulf of Mexico, is one of the most complex passive continental slope systems in the world. Salt tectonics have created geologic structures at the rate of several centimeters per year. Bed forms, furrows and areas devoid of recent sediments indicate the occurrence of high-velocity, deepwater currents.
The plan is to characterize the geologic and geotechnical conditions in this region and determine how best to optimize these characterizations, since the conventional investigation program for designing an offshore foundation may not always be practical for deepwater anchor systems with regard to cost and schedule.
Finally, the study plans to determine installation and capacity predictions for suction caisson anchors and vertically loaded anchors. Most of the SEPLA aspect of vertically loaded anchors is expected to be handled by another study. The Texas A&M study, therefore, hopes to focus primarily on drag embedment anchors, examining the trajectory of the anchor during installation and the holding capacity of the anchor under inclined loading.
Experiments will begin with a comprehensive investigation testing scaled models of reasonable size, eventually leading to larger field tests. A computational study also will address the effects of inclined loads, as would be imposed by a taut anchor.
Many other studies are under way at different research centers, and ultimately some of the centers may cooperate on the research. Ultimate deliverables include a "state-of-the-practice" report detailing findings from the study, site characterization reports based on the Gulf of Mexico site investigations, and installation and loading prediction reports on vertically loaded anchors and suction caisson anchors. For more information, visit www.otrc.tamu.edu.
Tender-assisted floater design Norwegian companies Kværner and Smedvig have delved into joining the time-honored drilling tender with the floating deepwater platform - particularly the tension-leg wellhead platform (TLWP) - to conduct development drilling operations. They deem it an ideal way to plumb deepwater reserves in relatively benign environments, and such a system could be field-ready in a relatively short time.
The system could be used with other types of floating production facilities as well, including spars and deep-draft production vessels. However, the negligible heaving motion of most TLWPs makes them the production platform of choice for such a system.
The research reveals a tender-assisted TLWP to be economically attractive, particularly for field development off West Africa or in Southeast Asian waters. Drilling equipment investment would be held at a minimum, mainly because drilling tenders already exist that, with some minor upgrading, could tackle the job. New tenders designed specifically for drilling with floaters also could be built for a lot less than the alternative, which entails including a relatively permanent, full-size drilling unit on the tension-leg platform (TLP) or using a conventional mobile rig to drill subsea tie-ins to the floating production unit.
Several workable connection systems are practical for joining tender vessel and TLWPs to allow dry well completions. This would simplify production schemes and cut operating costs significantly. Considerable savings also would come from the ability to build the TLWP without having to expand its above-water work area to accommodate the rig and its associated dry and wet loading. Instead, the tender would do its designated job by erecting a full-size portable derrick aboard the TLWP, then fulfilling all other drilling and storage requirements itself, including crew quartering. This also would increase the safety factor.
The self-erecting drilling rigs carried aboard today's tender vessels range typically from 1 million lb to 1.2 million lb gross nominal capacity and 750,000 lb to 1 million lb hook load capacity. All are fitted with top drives and 2,000-hp drawworks. Cranes aboard the tender would be used to erect and dismantle the rig on the TLWP.
The main challenge related to tender-assisted drilling on a floating wellhead structure is the stable station-keeping of two independently moored floating structures that are in immediate proximity. Kværner and Smedvig believe the best-suited connection should be made of soft polyester rope or a system that yields soft stiffness, such as a yoke. This would not affect the primary means of mooring for either the tethers of the TLWP or the line mooring of the tender.
However, the designers believe development of the final configuration should be based on field-specific environmental criteria and the operator's overall philosophy.
The companies estimate capital expenditures for a TLP with permanent drilling setup and 24 well slots would cost about $143 million for a typical West African deepwater development, while capital expenditures for a tender-assisted TLWP with the same number of well slots would be more like $59 million. For 12 well slots, the TLP would cost about $133 million, while the tender-assisted TLWP would cost some $36 million.
Kværner is marketing the concept to operators with future development plans off West Africa and in Southeast Asia.
The study was detailed in a presentation at this year's Offshore Technology Conference (OTC 12988) by Stig Botker, Terje Karp and T.B. Johannessen, all of Kværner Oil & Gas A/S, and Marcus Chew of Smedvig Asia Ltd.

Comments