OTC papers highlight technological advances

• Shell's latest Gulf of Mexico deepwater developments [11,548 bytes]
• Kvaerner Oil & Gas International's floating production, drilling, storage, and off- loading vessel (Fpdso) concept incorporates a drilling rig on top of a floating production, storage and offloading vessel turret. Image courtesy of Kvaerner. [8,479 bytes]
• On Jan. 21, 1998, the Miracl laser conducted a 4 sec test on a sandstone sample, cutting a 6-in. long, 2-in. wide hole at a penetration rate of 170 ft/hr. Photo courtesy of Colorado School of Mines. [199,937 bytes]

This is the second of two articles rounding up OTC coverage.

A selected roundup of late technical presentations at the Offshore Technology Conference focuses on advances in drilling, production, and pipeline technologies.

At final count, OTC attracted 49,641 attendees, up from 43,394 in 1997 (OGJ, May 11, 1998, p. 27).

Speakers provided snapshots of major developments in the Gulf of Mexico and Norwegian North Sea, new offshore floater concepts, an innovative subsea mudlift system, cutting-edge laser drilling techniques, and the use of 3D seismic to solve water flow problems in a Gulf of Mexico field.

Subsea systems

Shell Deepwater Development Inc. continues to be a leader in deepwater installations, as evinced by its Gulf of Mexico Mensa subsea project winning this year's OTC distinguished achievement award.

Shell has three more subsea projects slated to go on stream in the next 2 years. It estimates the Macaroni, Angus, and Europa developments (see illustrations, this page) will cost nearly $1 billion and recover 300 million boe.

Mensa, Mississippi Canyon Block 687, is a subsea gas development in 5,300 ft of water tied back 68 miles to a host production facility. By Shell's count, Mensa established about 25 technological firsts. Mensa started producing in July 1997 and, as of this month, produces 250 MMcfd from two wells. Shell expects the third well, being drilled, to start producing in August, increasing Mensa's flow to over 300 MMcfd.

The Mensa project has not been without problems. D.C. McLaughlin, Subsea Engineering Manager, Shell Deepwater Development Inc., said that the project is now estimated to be about 15% over its $290 million budget. He blamed much of the cost overrun on extra outlays for drilling rig, transportation, logistics, terminal support, and offshore technical services. Rig day rates increased by 70% over the life of the project, McLaughlin said.

Shell also incurred extra costs because of crystallization of the CaCl₂-CaBr₂ completion fluid, a need for contingency liners in all three wells, initial failure of the electronic workover controls, and dropping of the main pipeline that later experienced a leak in deep water. A leaking methanol line within the utility umbilical forced Shell to change to a glycol system for hydrate inhibition during well start-ups.

One major incident was the failure of the connector between the upper and lower portions of the 4-in. by 2-in., 10,000-psi guidelineless subsea tree on Well A-1.

The upper portion of the tree contains the swab valves, wing valves, production bore piping, erosion detector, pressure and temperature transducers, production choke, production orifice valve, flow line connector, tree chemical injection isolation valves, and hydrate circulation valves. The lower tree includes the master valves, crossover valve, crossover loop, and downhole chemical injection isolation valve. The split-tree design allows the upper tree to be retrieved and replaced without killing the well. Shell said the valves in the lower portion functioned as designed when the connector failed and shut in the well.

After analyzing the failed parts, Shell said the parts met American Petroleum Institute standards, but it contends the API standards lack toughness criteria. Shell indicated it plans to submit a proposal to API for upgrading the standards to include toughness specs.

Shell changed out the upper portion of the A-3 subsea tree because it found that one part on the Well A-3 tree had been manufactured in a similar manner to the failed connector on Well A-1.

Mensa flow lines

Engineering and installation of the Mensa flow line for Shell Deepwater's Gulf of Mexico project was described by R.T. Gilchrist of Shell Deepwater Development Systems Inc. and F.A. Kluwen of Allseas Engineering BV.

The Mensa 12-in., 63-mile interfield flow line was S-laid to a depth of 5,300 ft. The second end was terminated with a pipeline-end manifold (PLEM) fitted with vertical connection hubs and a horizontal jumper installed between the PLEM and Mensa manifold. The flow line maximum allowable operating pressure varies with location and has been calculated with consideration for maximum possible flowrates, pressure-relief facilities, and hydrostatic pressures, Gilchrist and Kluwen said.

Damage during construction was repaired with shaped-charge cutting devices, ROV-operated lift frames, ROV-operated pipe-recovery tools, and ROV-operated pipe-repair tools at 5,000 ft. Seven miles of pipe from depths at 5,300-4,700 ft were recovered up the stinger by "reverse lay" and later reinstalled.

Three 6-in., 5-mile intrafield flow lines were initiated with stab-and-hinge tools and terminated with vertical hub PLEMs adjacent the subsea wells, they said. The stab-and-hinge tools were deployed down an S-lay vessel stinger.

The PLEMs were welded to the flow lines on the surface and the entire assembly lowered into place. During raising/lowering sequences of pipe ends, with and without PLEMs, rotations of more than 500? were observed, said Gilchrist and Kluwen.

End cuts were made with a long baseline acoustic position system for reference. These repeatedly yielded actual positions within 1 m of target. Each intrafield line was fitted with 15 lift frames at 500 ft intervals starting at the subsea wells. These were placed via a coordinated procedure involving lowering by cable and near-bottom ROV guidance.

Ekofisk redevelopment

Work is nearing completion at Ekofisk, where the nearly 30-year-old field complex is undergoing major redevelopment. The project, called Ekofisk II, was prompted by high operating costs caused by aging facilities and subsidence.

G.H. Landa, W.H. Holm, and E.V. Hough of Phillips Petroleum Co. Norway noted in a session devoted to the project that the decision to redevelop was made in 1993.

The project involves installing a new processing platform (2/4J) and a new wellhead platform (2/4X) near existing facilities as part of the field transportation and processing complex. This complex has been transporting hydrocarbons from Valhall, Hod, Ula, Gyda, Tommeliten, and Statpipe fields in addition to production from the greater Ekofisk area. Four outlying fields within the production license area of Ekofisk are being shut in: Albuskjell, Cod, Edda, and West Ekofisk.

As part of the project, Phillips reached an agreement with Norwegian authorities to extend the production license from 2011 to 2028 and provide royalty relief on oil sales.

Ekofisk II redevelopment is prem- ised on tying in Eldfisk, Embla, and Tor fields in addition to Ekofisk field, the authors said.

The new processing facility has been designed for an oil capacity of 235,000 b/d and a gas capacity of 789 MMscfd. This would lead to a plateau on gas for 3 years after start-up; oil production would plateau for 2 years.

Two existing wellhead platforms, 2/4 Alpha and 2/4 Bravo, are to be phased out in 1999. Production from these platforms will be replaced by the new 50-slot wellhead platform (2/4X). A total of 45 new production wells will be drilled with a new platform rig on 2/4X and with a leased jack up. Drilling will take about 4 years for all 45 wells.

New concepts

Kvaerner Oil & Gas International unveiled two new offshore floater concepts. Its floating production, drilling, storage, and offloading vessel (Fpdso) incorporates a drilling rig on top of an FPSO vessel turret (see illustration, this page). The concept was developed jointly with Single Buoy Moorings Inc. (SBM) in cooperation with Statoil AS.

As explained in a presentation by Leiv Wanvik, Kvaerner, and Leen Poldervaart, SBM, the vessel is kept on station by the turret mooring assisted by thrusters in bad weather.

The authors see this type of vessel being used primarily in deepwater and harsh weather conditions. But it could also be economical in shallower waters if a large number of wells are drilled from the vessel.

Kvaerner's second concept is a deep draft floater (DDF) production facility with workover or drilling capabilities suitable for water depths of 400-6,500 ft. Like the tension-legged (TLP) or spar production facilities, this concept allows for dry wellheads, although wells could be completed subsea and connected to the DDF with a flexible well riser.

According to Kvaerner, this facility has greater water depth and topsides weight limits than a TLP, as well as being less complicated to manufacture than a spar facility.

A multi-function concrete barge (MFB) concept was described by C. Valenchon and J.H. Rossig, Bouygues Offshore SA; and by G. Pouget, Sedco-Forex, and F. Biolley, Institut Français du Pétrole.

The concept adds drilling, tieback, completion, workover, and surface tree capabilities to a vessel similar to the concrete monohull installed in Elf Congo's N'kossa field off Congo. The N'kossa vessel contains facilities for oil and gas treating, utilities, and living quarters. The authors see this concept as ideal for developing deepwater fields in mild environments such as the Gulf of Guinea.

Subsea mudlift system

Riley Goldsmith, Goldsmith Engineering Inc., described a subsea mudlift system for deepwater drilling applications. In place of a conventional, single-gradient circulation system, where drilling mud is pumped down the drillstring and bit, then back up the annulus to the surface, the mudlift system uses subsea pumps to boost drilling mud directly from a connection above the subsea blowout preventer to the drilling vessel.

With a mudlift system, a dual-gradient system is created that:

• Exerts a pressure gradient from the bottom of the borehole to the seafloor.
• Maintains a seawater pressure gradient from the seafloor to the vessel.

The mudlift system can potentially eliminate two or more casing strings, especially in deepwater environments. This is because a dual-gradient system can be designed to better match pore-pressure gradients with formation-fracture pressures.

With a conventional riser and circulation system, the drilling mud within the riser exerts a pressure greater than seawater normally would at the mudline, especially if the drill mud is weighted up to control high pore pressures.

For example, if a 16 ppg mud is being circulated through the well bore, the fluid gradient between the seafloor and vessel will be about twice as great as compared with seawater alone. This places an additional pressure burden on non-cased horizons. With a mudlift system, this additional pressure burden is reduced, and casing intervals can be set deeper.

In addition, the mudlift system will improve drilling performance because it provides twice the hydraulics of a conventional drilling system and allows control of overbalance without changing mud weight.

The greatest obstacles to the mudlift system concern equipment design and redundancy for the subsea pumping, control, and diverter systems. Because maintenance on the subsea pumps and equipment must be minimized, new levels of operating efficiency must be realized. Goldsmith said that the mudlift system can be configured for both riser and riserless drilling.

Water flow identification

The integration of high-resolution 3D seismic, conventional 3D seismic, and well-log information helped identify the internal geometry and lateral extent for a sand unit known to produce water flow problems in a Mississippi Canyon field, according to William J. Berger, marine geologist for Geoscience Earth & Marine Services Inc.

In the Gulf of Mexico, flowing water sands originate from saturated and slightly overpressured aquifer sand bodies in depths as shallow as 1,000 ft below the mud line. When penetrated by a well bore during the drilling process, equilibrium and confinement is interrupted, and a conduit of vertical migration commences.

"The process may result in a slow migration of the fluids up the well bore or along the outside of unsealed casing until the flow breaches the seafloor and causes a venting of water and sand on the seabed," Berger said. The sand unit may form a void, and the casing may lose its lateral support, "buckling under its own weight."

Berger said it is possible to identify the top and base of the water flow zone using conventional 3D seismic, but high-resolution 3D seismic is needed to map the lateral extent. "From the high-resolution data set, we can see individual bedding planes and displaced horizons that can be correlated across rotational scars," Berger said.

Contrasted with conventional 3D seismic data, high-resolution 3D data allow geophysicists to decipher horizons on the order of 10 ft instead of 30-40 ft.

The high-resolution 3D survey in the Mississippi Canyon field resulted in a bin size of 20.5 ft by 49 ft, compared with conventional surveys resulting in bin sizes of 41 ft by 131 ft.

Laser drilling

A panel discussion with representatives from Gas Research Institute (GRI), Colorado School of Mines, Solutions Engineering, U.S. Air Force Research Lab/DELC, and the U.S. Army Space and Strategic Defense Command said a 2-year laser drilling study is moving forward as planned.

Although the idea of using laser technologies for drilling and completion applications is not new, only recently, with technology transfer and facility availability from the U.S. military's "Star Wars" satellite laser defense program, has laser technology become a potentially viable drilling method.

An improved understanding of laser applications could lead to the development of downhole laser drilling machines, laser-assisted drill bits, laser-perforating tools, and sidetrack and directional laser drilling devices.

Studies show that rock chipping occurs at 130 kw, melting at 433 kw, and vaporizing at 1,039 kw.

Two years ago, Phillips Petroleum Co. experimented with one of the more promising laser technologies, the mid-infrared advanced chemical laser (Miracl), at the U.S. Army's High Energy Laser System Test Facility at Kirtland Air Force Base, New Mexico. Phillips subjected a 5/8-in. thick shale, sandwiched between two 7/8-in. thick Berea sandstone samples, to the 1.2-MW, 3.8-micron laser. Within 1 sec, the laser completely bored through the sandstone and shale, equivalent to 450 ft/hr.

More recently, the Colorado School of Mines conducted another test on a sandstone sample using the same laser and facility with comparable results (see photo this page).

Similar to a rocket engine, the Miracl laser works by burning ethylene fuel with a nitrogen trifluoride oxidizer, producing fluorine as one of the combustion products. Downstream from the combustor, deuterium and helium are injected into the exhaust. The deuterium forms with the excited fluorine to form deuterium fluoride molecules, while the helium controls the temperature and stabilizes the reaction. Output power can be varied over a wide range by altering the fuel flow rates and mixture.

Although application of this technology for drilling purposes is still in the inception stage, Richard Parker, principal technology manager for GRI, said that, "Achieving a technological breakthrough with laser drilling could generate the kind of radical change that occurred at the turn of the century when the rotary drill replaced cable tools.

Contributing to this article were Drilling Editor Dean Gaddy, Production Editor Guntis Moritis, and Pipeline/Gas Processing Editor Warren True.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.