While not a stated goal, many in the industry consider the 100-mile subsea tieback from a subsea installation to a fixed structure or floating vessel receiving production to be the next major mile stone in deepwater development. Referred to with irony as the "holy grail," this arbitrary distance brings into focus the technology, economics, and geology that must come together to make such a project not only possible, but practical.
As more large oil and gas fields are discovered and developed in remote deepwater areas, the concept of the hub and spoke subsea development has grown in popularity. Tying back to a host manifold, these satellite wells can be anywhere from 200 yards to 20 miles away.
Driving this scenario is the advantage of gathering production from far flung wells to feed into some sort of offshore processing system, that in turn ties back to shore or other export facilities. This centralizes the expensive processing infrastructure and uses the production from several wells to offset the expense of such a facility.
A new factor in this equation is the excess capacity showing up on many of the established platforms in the US Gulf of Mexico. Installed at great expense, these platforms are finding a secondary market leasing out their excess throughput and processing capacity to nearby subsea fields with such needs.
It doesn't take too much imagination to see a future in which the existing infrastructure in the Gulf outlives the fields it was designed for and installed on. Using simple tiebacks, these platforms would lease out capacity long after their primary fields have played out.
State of the art
Currently, there are a number of very long tiebacks in the US Gulf of Mexico, as well as West Africa, offshore Brazil, and the North Sea. While Shell holds the record length tieback with Mensa - 68 miles to a processing platform in the Gulf of Mexico - the majority of these are less than 20 miles.
Doug Peart, Manager of Subsea Projects for Shell Deepwater, said that while Mensa is the longest subsea tieback existing, any other tieback in the 20-mile range could be considered leading edge.
"I think 20-25 miles is as good a round number as you're going to find," he said. While 20 miles is not unusually long for a gas development, for an oil field, it is an achievement. Not only is it difficult to send oil production 20 miles from the reservoir, but it is expensive. Peart said it all comes down to the size and nature of the reservoir. With existing technology it is "possible" to accomplish a 100-mile tieback, given the right set of reservoir conditions.
Distance from infrastructure is a key component in the decision to install a long tieback. As exploration, and eventually development, moves further offshore in the US Gulf of Mexico, pipelines to link with the existing natural gas grid will become more expensive and difficult. Remote developments are the most likely candidates for long tiebacks.
Tying back to an existing processing platform can save money in some cases, but there are a number of factors to consider. Deepwater wells tied back to the shelf must push production uphill, through very cold water over a long distance. Under these conditions, flow assurance becomes a key consideration and along with it the composition of production.
In the final analysis, it could be cheaper to install a floating production system to service a deepwater field, rather than deal with the expense of tying back production. The solution depends in the specifics of the reservoir.
Deepwater tiebacks
There seems to be some consensus that if a 100-mile tieback were to be pursued, the field, probably natural gas, would be in deepwater, where most of the large gas fields are yet to be discovered. To justify a long tieback, the field would have to be outside the reach of existing infrastructure.
Because of the expense of such a long tieback, it would require a large field with sufficient drive energy and dry gas. Only large, highly productive fields would be able to offset the immense cost of such a project.
Some experts estimate that once all costs are in, a 100-mile subsea tieback could be a "million-dollars-a-mile" project. To cover these huge up-front costs, initial production would have to be very high. Dry gas can be propelled by reservoir pressure efficiently over long distances through cold water and uphill. Liquids on the other hand present serious flow assurance problems that would point toward an alternative development system.
Another factor to weigh in this equation is the availability of alternative floating production facilities. In many cases, a floating production, storage, and offloading vessel (FPSO) would eliminate the need for a long tieback, as would a TLP, Spar, or other surface-piercing structure that can accommodate to flexible production and sales risers.
These vessels can be moored or dynamically positioned over a remote field. Wells can then tie back to a host manifold, which in turn is connected to the FPSO, or production rig, that offloads production to shuttle tankers or export pipelines. However popular in other theaters, FPSOs are not currently allowed in the US Gulf of Mexico.
There seems to be some disagreement over whether this US policy had led to a larger number of extended tiebacks in the Gulf. The specific reservoir profile needed to justify a long tieback may simply be more common in the Gulf than elsewhere.
Not only is the size and drive energy of the reservoir important, but the amount of liquids being transported also plays a role. The liquids bring up flow assurance issues associated with the formation of hydrates and paraffins. Although reservoir energy, or pressure, is what would drive production along a 100-mile flow line, if the pressure is not adequate, then a boosting system may be required. Any of these factors could change the equation substantially affecting the choice of production system.
Reservoir characteristics
The ideal reservoir for an extended tieback, according to Peart, is one that has high energy, a lot of dry gas, and is expected to come on strong and play out fast. Such a field will pay big dividends early in the development, but not the kind of long-term returns that would justify the cost of a floating production system.
By contrast, an inconsistent formation, one that produces a large amount of liquids late in the development cycle or requires frequent workover would not be a candidate. The type of flexibility required to maximize such a field would be much more cost effective on a floater than in a subsea system. "Certainly in the surface world, you will have more flexibility down the road," Peart said.
If the gas drive is not high enough or production relatively trouble-free, the long tiebacks would have to give way to a TLP, spar or other surface piercing structure that could accommodate the changing requirements of the field. Adding processing equipment is much easier on the surface than subsea.
Bearing this in mind, Peart said the question being considered is: how do you produce a system that can maximize production all the way through the life of the field when the reservoir performance changes over time?
For an unpredictable reservoir, there has to be flexibility built into the system up front. If the system is to be a subsea tieback, the extra cost is borne up front to install solutions for problems that may or may not occur down the road.
For example, will the system require multiple flow lines of varying sizes so it can switch from one to the next to the next as the water cut goes up. Should the system have a built-in option for boosting capacity that may be needed later in the life of the field to accommodate declining pressure, or increasing water cut. Such options are expensive and change the economic model of the development, Peart said.
Technological challenges
When asked what it would take to tieback 100 miles, the initial reaction from industry experts is uniformly - "money." As stated earlier, this system would have the potential of becoming a million dollar-a-mile pipeline. Beyond the simple economics there are a handful of strictly technological challenges.
- Flow assurance tops many lists as the biggest technological concern. Historically, tiebacks have relied on well pressure to drive production. One hundred miles is a long distance to drive production. Add to this that the flow would almost certainly be uphill and there are going to be flow assurance problems.
- Added to the equation are the factors of paraffin and hydrate development. Paraffins can be inhibited chemically, but that requires an injection system at the source. Hydrates form when the flow cools and ice crystals block the pipe. Hydrate formation can be controlled in many cases by insulating the flow line so the production doesn't cool enough to ice up between the well and the host.
- In the case of 100-mile tieback in deepwater, Pete Stracke, Manger of Field Development for Oceaneering, said there might be a need to heat the flowlines. This could be done using a tube within a tube (concentrically) to circulate warm water inside the flowline, keeping the production warm enough to avoid wax deposition formation. Both the chemical injection, which would add to the size of the control umbilical, and the heating system would substantially increase the costs to the project.
- To guarantee flow, a pigging system might be required. That means instead of a single flow line, two would be needed to circulate the pig. The pig could be launched subsea from the host template, but would need the second flow line to return to the launch station. Stracke said installing such a line would be a technological achievement in itself. Typically spooled, such a flow line would exceed the capacity of any reel system. The largest of these, according to Stracke, can carry a about 8 miles of 4.5-in. pipe.
A practical limit
From the standpoint of technology, Peart agrees with Stracke that controls and umbilicals are definitely on the critical path. Transmitting hydraulic fluids over this great distance requires larger hoses, which in turn require larger reels, meaning more reels of umbilicals and control lines would have to be sent offshore and then spliced. Peart said this does not mean such a solution can't be accomplished, but it would be accomplished at a price.
"I don't think the big issues are around the hardware, I believe we could extend the hardware. The question is: 'Have you now cast a practical economic limit on what you can do?'" Peart said.
A relatively new technology may offer an alternative to the extended control lines and umbilicals. Rather than running control and umbilicals back to the host platform, it may be possible to place a buoy above the subsea well and connect the two with umbilicals and control lines. The buoy would relay commands radioed from the host platform to the subsea manifold, eliminating the need to tieback the umbilical and control lines. As far as remote telemetric control systems, Peart said Shell has considered these in the past, but so far has been able to accomplish its extended tiebacks with conventional control systems. Still, he did not rule out the role these new systems might play in tiebacks of greater distance.
"As you go to 100-mile tiebacks, I think you have to open the door again to those types of technologies," he said.
With the Mensa 68-mile tieback, Shell designed for a reservoir thought to be dry gas with very little water and substantial pressure support that would die rather quickly. Given this profile Shell opted for a very straightforward system with little flexibility and relatively low costs. From a technology perspective, the hardware could be extended to accommodate the reservoir performance and size without the need for many optional extras. It is this scenario Peart reflects, in his opinion of what type field would most likely lead to the first 100-mile tieback.
The first site
Shell Deepwater has concentrated its longer tiebacks in the Gulf of Mexico, although there are some extended subsea tie backs in the North Sea (the tieback on the Troll Osberg Gas Injection project in the Norwegian sector of the North Sea was 30 miles). Peart said this does not mean the ultimate tieback would follow this pattern. He believes it could in fact occur anywhere.
Even though there is more infrastructure in the mature theaters than in frontier areas, the real test for a long-distance subsea tieback is the economics. If a field was far enough from the "grid" that a 100-mile tieback would be needed, then the choice is between surface and subsea systems.
"I think hardware-wise, we could reach to 100 miles," Peart said.
