Deepwater focus shifts from ingenuity to reliability
Jeremy Beckman
Editor, Europe
- FPSO Petrojarl Foinaven loading crude into shuttle tanker Petrotroll. (Photograph courtesy of British Petroleum).
- Schiehallion FPSO at Harland & Wolff yard, Northern Ireland.
- One of Fugro-GEOS' real-time seabed current monitoring systems developed for BP in the Atlantic Margin, deployable via a command unit on a surface vessel or semisubmersible. An electromagnetic current meter is interfaced to a modified acoustic release unit. Encoded data are then telemetered acoustically. At the surface, a hydrophone receiver unit suspended over the rig's side receives the near-bed data and connects via a cable to a control room PC. Current speed and direction, sea temperature, and salinity measured every 10 minutes are displayed in real time.
- One of the West of Shetland production concepts prepared by Brown & Root, depicting surface separation, local power and host water injection.
The reasons became clear at a recent SMI-organized conference in London, "The Economics of Exploration and Development in the Atlantic Margin." Euphoria over BP/Shell's triple oil strike in the early 1990s (Foinaven, Loyal and Schiehallion) was halted by the costs of the developments that followed - particularly at Foinaven, where two years' lost revenue caused by production delays was recently compounded by the plunging oil price.
Foinaven, like Schiehallion, was sanctioned during the good times of $21/bbl. "Had BP CEO John Browne been presented with the actual running costs," said analyst Tony Mackay, "he would probably have vetoed both projects." Mackay's figures predicted rates of returns way below the average for other sizeable North Sea projects such as Forties and Gannet.
BP might still save face by extracting the maximum value from Foinaven and Schiehallion - both are potentially 500 million bbl reserve fields. On the other hand, suggested Mackay, BP may knowingly have done a favor to all operators West of Shetland by pushing these projects forward as test cases. A key imperative learned from Foinaven, where a leaking manifold was one source of bother, is the need for ultra-reliable subsea components.
Andy Tillbrook of Amerada Hess said this was higher on his shopping list than futuristic, untried technological solutions. Alex Hunt, of Texaco, the other operator to give a paper at the conference, was more interested in post-development profits than minimizing capex.
Harsh environment
Tight hole status is etiquette for Shetland area wells, but there are at least six known discoveries. Experience to date suggests that the south of the province is more oil prone - examples are Amerada's Solan and Strathmore and BP's Suilven fields - while the north is the place for gas deposits such as Texaco's Torridon and Victory. The mainstream area of interest ranges from 500 meters water depth (Foinaven and Schiehallion) to around 1,400 meters.Recent drilling in West of Shetland has been dominated by development work on the BP/Shell projects. However, a combine led by ARCO and Conoco is about to drill promising acreage adjacent to Suilven's block in waters of 1,000 meters-plus. Exploration drilling may revive further as more 3D seismic data becomes available, and operators meet their license obligations.
Rig sharing in these waters is practical, as drilling costs are higher than in the North Sea. The hostile metocean conditions will inevitably incur downtime - and with rig rates for this sector scaling $300,000/day, that is a big worry for the operators. The same applies to development engineering, as grounded installation vessels can also rack up huge bills.
Kongsberg Offshore's Ingmar Nyheim suggested the problems were not insurmountable. Subsea production systems are being designed for installation by a drilling semisubmersible, he pointed out, obviating the need for an installation vessel. "Rigs can also work in a wider weather window, using cranes. Simultaneously, intervention and tie-in tasks can be performed with the drilling activity."
Fugro-GEOS' Robert Stephens suggested that contractors could mobilize rigs at short notice to perform set tasks, based on accurate short-term weather forecasts. But he admitted that the industry was some way off modeling accurately the environmental processes that affect this region. Years of intensive data gathering lie ahead, he warned. However, Texaco's Alex Hunt pointed out that new data was already entering the public domain from the Russian Navy, which stationed submarines in the area during and after the Cold War.
Thermal extremes
Fugro-GEOS' own work to date has been collaborative with the various Shetland operators, especially BP. Over the past few years, seabed measurements have been taken progressively deeper along the continental slope, with 1,400 meters the target this year.Between the Shetland and Faroe Islands, Stephens said, there is an interactive process of cold water moving southwest from the North Sea, warm Gulf Stream water pushing north from the Atlantic, and another band of cooler water descending from the Faroes. "Where you are in relation to hot and cold water dictates your environment, but it's never static - the warm water front can move back and forth."
Temperatures of -1.5°C are encountered typically at 500 meters water depth, although local fishermen have recorded transient lows of -5°C. "This affects viscosity of oil in this region," said Stephens. "However, the top 50 meters of the water layer can be warmed-up in the summer, resulting in the main body of water being much warmer than the cold area. The rapid transition from one to the other leads to energetic dynamics," cautioned Stephens.
Resultant current conditions will impose significant stresses on subsea components, he warned, while load wave conditions - a very large fetch across the Atlantic - allow large swell trains to develop. Prolonged periods of high energy swell waves can ensue, which represent the main hazard for exploration drillers. And these waves could coincide with severe currents.
Drilling riser designers must beware extended periods of a uniform current profile, he counseled, which can potentially generate vortex-induced vibration. "In very heavy swells, there may be a need to cease operation of a semisubmersible even in DP mode, due to the impact of heave on the drill table."
Lateral solutions
These awkward conditions, allied to the area's remoteness, demand new strategic approaches, said Andy Tilbrook, New Technology Coordinator at Amerada Hess. Sober analysis of the Atlantic Margin today suggests small to medium-sized accumulations are more likely to prevail than giant fields. But while other deepwater basins are being developed through connected infrastructure, that may not be appropriate for the Shetland area, he suggested.There has been clamour for a new trunkline from the region to northern Scotland to kick-start development of the smaller discoveries - but at what cost, said Tilbrook? In addition to pipeline charges, operators would have to pay for pumps to move fluid through the pipelines, for chemicals to keep them clear of waxes, hydrates and asphaltenes, and there would almost certainly be high field downtime, with all points in this infrastructure unlikely to be maintained simultaneously.
So what was his proposal for boosting uptime? The suggestion was a floating production, storage, and offloading vessels (FPSO) offloading oil to tankers, which is precisely the solution that Amerada Hess has favored for
all its recent North Sea developments, including Bittern/West Guillemot. This is a joint project with Texaco and Shell, as is BP/Shell's current multi-field ETAP development.
"That kind of cooperation could also be the way forward for clustered Atlantic Margin fields," Tilbrook said. "A spar buoy might also work. Being mostly under the surface of the water, it would be less prone to weather downtime than a monohull floater," he said, "so maybe cheaper."
Amerada has pioneered FPS re-use in the North Sea, deploying the Petrojarl I on the Angus and Hudson fields. Why not in the Atlantic Margin as well? Tilbrook postulated owning or leasing more than one FPS - a smaller one, perhaps, for when production rates are lowest, with a larger one brought in for mid-life peak production.
Alternately, subsea separation could be brought in late on when increased water cut threatens production. Extended discovery well tests could become an integral part of the local development strategy, he added, since production is the best way of ascertaining reservoir compartmentalization.
For him, the metocean volatility implied higher intervention costs than in other deepwater basins, making hardware reliability and simplicity paramount. It was better to transport and treat oil via a system that was 85% efficient, but 100% reliable," he claimed, "than to risk downtime costs from technology 100% efficient, but only 85% reliable."
Another way of limiting OPEX in the Atlantic might be to contract out utilities - he cited the Raw Wayer injection project in Europe, which aims to inject water from deep in the water column via a remote subsea manifold. Electrical power could also be managed by a contractor, he suggested, perhaps generated by gas from some of the fields.
Merchant bankers are viewing this idea favorably for the Atlantic Margin, he said, adding that the generated electricity could also be fed into Britain's national grid. Spare gas could in addition power offshore wind turbines during slack periods, an idea which interested the British government, he claimed. And it might prove a more attractive option for the operators than gas sales to the mainland, with local beach prices predicted to remain low.
Deepwater drivers
Tilbrook noted the fashion currently for engineering contractors is to marinize their equipment with the aim of driving the industry towards deepwater unmanned operations. But some of the proposed technologies may prove too complex, specialized, or expensive, "The key aim should be to eliminate intervention."- Branched wells: Drilling contractors are pushing branched wells to decrease development well numbers. But multilaterals present risks in a hostile deepwater environment, he feared, as they channel perhaps too much of a field's production through a single well. "I'm also concerned about the use of elbow joints in multilateral wells, and keeping these clear of scale, waxes and asphaltenes."
"I'm not convinced they're suited for repeated thermal cycling as well as a mechanical/composite mix. The question is, if you design a riser for mechanical strength, what strength do you have to consider? If the pressure within the oil-bearing riser is greater than the external hydrostatic pressure, why design it to meet high external stresses? Surely the main point is to get fluids from A to B?
"Maybe it's worth considering whether use of a single material (with a single co-efficient of thermal expansion) could provide greater benefits than current composite material flexible risers."
Hydrate solution
Another dilemma for west of Shetland operators is how to use their associated gas efficiently, rather than simply reinjecting it. Tilbrook was against gas-liquids conversion as being unreliable, even dangerous in unmanned operations. Amerada is co-funding a project by NTNU in Trondheim, Norway on conversion of gas to solids. This might allow gas hydrates to be transported with the oil as a slurry, or stored on the seabed as a future energy source. Results so far look promising, he said.Production concepts
Unlike Norway's Haltenbanken or Voering Basin, the Shetland area has thrown up few huge fields. That has not stopped the industry planning for "the big one," if and when it comes, as well as smaller facilities tapping field clusters.Texaco UK could, in theory, have drawn directly on the Deepstar (Joint Industry Project) program for its Victory and Torridon fields, but found it hard to equate the harsh, remote West of Shetlands with the benign, infrastructure-laden Gulf of Mexico. So, along with Amerada Hess, it contracted Offshore Design Engineering (ODE) in 1996 to evaluate different production concepts. Unlike some, ODE was not trying to push a single concept, said Texaco UK's senior facilities engineer Alex Hunt.
As BP discovered, he said, minimizing CAPEX was not the be-all and end-all - "we prefer to concentrate on getting economic returns. So we started with a qualitative review of all available concepts, including the more wild and woolly ones. These were shortlisted down to six - an FPSO, a compliant tower, TLP, spar, semisubmersible and a deep draft semisubmersible. The latter is actually a spar with well slots inside, which can take rigid risers and dry trees, unlike a normal semisubmersible."
Plenty of negatives started to emerge. A semisubmersible would need two tanker loading points and twice as many shuttle tankers. The discovered fields tended to have low gravity oil, low GOR, low energy and shallow reservoirs, which all added up to low productivity. To attain decent production, Hunt said, a large number of wells would be needed, leading to high drilling costs.
"It also looked like we would need a large amount of heavy topsides with a lot of rotating equipment and pumping equipment consuming a lot of power. Hence Amerada's shared power generation idea.
"This led on to two scenarios. First, a field does not mean a single reservoir. If you get enough small pockets close together, these can be exploited. But if they are 10-13 million bbl pockets, that requires a lot of appraisal and wells, and hence time and cost. The other scenario is that the field could be spread out across a wide area, which would mean at least one subsea manifold to gather in the various reservoir clusters."
Compliant towers were looked at out of politeness to parent Texaco, but did not emerge well, chiefly because they are not designed for waters beyond 800 meters. Also, installation problems occurred in the US Gulf of Mexico last summer in 600 meters. For small oil facilities (300 million bbl field producing 90,000 b/d), FPSOs ought to have won hands down, due to the technology's maturity.
But ODE's study showed that the rate of return was not actually much above the other four concepts, and spars and TLPs have since closed the gap further. For large oilfield facilities (600 million bbl and 180,000 b/d production), FPSOs actually looked less attractive, because they require more subsea wells. "Potentially though," Hunt said, "all concepts except the compliant tower looked economic."
Gas field needs were also reviewed. The known gas reserves in the region appear normally pressured, but liquid yields are low - "that makes you vulnerable to gas prices," Hunt commented. The combined impact of low well productivity, high drilling costs, and hydrates formaton militated in favor of conventional subsea equipment rather than expensive subsea trees.
Up the slope
"The low liquids level means dense gas phase exports are possibly part of the way up the seabed slope, but not all the way to the shore. However, manifolded flowlines may need heating, which means well tests are critical in order to get good samples for chemical analysis."We accepted that we'd need a big gas accumulation to get under way, but to date, we have not found a single 3 tcf accumulation in this area. We are finding pockets of gas, but can we knit them into one mass?" With the gas market's built-in swing factor, topsides equipment could be sized bigger than what might be needed in future, Hunt said - however, doing so would hit CAPEX.
The production facility envisaged would handle 850 MMcf/d, with one main and one satellite drilling center. FPSOs were rejected, partly due to misgivings over higher pressure gas heading through an external swivel toroidal path, instead of through a pipeline. As for the other concepts, no clear winner emerged, to the operators' surprise.
The screening study did lead to an investigation with Spars International into harsh environment spars - Aker and Amec have recently mounted a study on this subject. "The problem with the spars we looked at," says Hunt, "was that they didn't have enough storage on board, only buffer storage - even the ones being looked at now for the West of Shetlands. The bigger you make the hull's diameter, the more susceptible it becomes to drag co-efficient from the variable currents, which in turn affects motion characteristics."
Other current initiatives in the region include AMJIG, a forum of the 22 operators along the Atlantic Margin, and the Aurora Project, initiated by Texaco, Conoco and Total, and recently swelled by BP, Mobil, and Shell. Initial work focused on gas infrastructure opportunities for Atlantic Margin fields. Aurora's second phase, due to be completed by September, is examining ideas such as tying back fields via subsea facilities all the way to the Shetland Islands, should there prove to be insufficient gas for a platform.
The assumption is that eventually there will be a gas pipeline in the area, making its way to St Fergus on Scotland's east coast. Aurora is working on a window of 2002-2005 for Atlantic Margin gas coming to the market.
Copyright 1998 Oil & Gas Journal. All Rights Reserved.
