Dynamic positioning versus mooring: debate continues as technology evolves

An anchor handling vessel deploying a mooring spread. A DP thruster used on Transocean's Discoverer Enterprise. [32,057 bytes] If a producer or drilling contractor is planning to build or convert a deepwater mobile drilling vessel, why would it choose to limit the vessel's future operating water depth potential by using a mooring system instead of dynamic positioning? Traditionally, mooring has limited vessels to maximum operating depths of 5,000 ft, whereas dynamic positioning (DP)

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Anatomy of a choice

Marshall DeLuca
Business Editor
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An anchor handling vessel deploying a mooring spread.


If a producer or drilling contractor is planning to build or convert a deepwater mobile drilling vessel, why would it choose to limit the vessel's future operating water depth potential by using a mooring system instead of dynamic positioning? Traditionally, mooring has limited vessels to maximum operating depths of 5,000 ft, whereas dynamic positioning (DP) allows a vessel to operate in water depths only limited by riser storage.

Is dynamic positioning not decisively attractive, compared to a mooring system? Are changes underway in capital costs and operating costs of both systems? And what about target operating depths? The latest efforts to drill and produce in ultra-deepwater are focusing attention on these issues again. Ongoing technological development won't allow firm resolution of the choice.

Debate without end

Which is better? The debate between mooring and dynamic positioning for the optimal stationkeeping scenario has been around since Foramer first put DP on the Toucan drillship in 1966. For the most part, there is an obvious split in the industry: DP preference or mooring preference.

There are many reasons why the debate has gone on so long. The main one is superiority of one technology versus the other. R.E. Steddum, Manager of Transocean's Structural and Naval Architecture group, explains: "I don't think that we have ever been able to establish that (superiority) conclusively. We have not seen a compeling analysis that one is superior to any other one."

Also, finding a direct comparison between the two technologies is almost impossible. An accurate comparison would be to match capabilities between newbuilds. But, the number of factors and different circumstances that can be favor one of the other are almost endless. The only concrete way to find a distinct winner would be to use a specific positioning location, and that is essentially how the decision is made for each project. Overall, there is no solid deciding factor.

Regardless of the preference of the drilling contractor, the ultimate decision behind the system of choice belongs to the operator. In the words of Charles Keaton, Vice President of Engineering and Operation Support Group for Global Marine, "whatever they are willing to pay for, we'll build." Simply put, it all goes back to the old adage, "the customer is always right".

So how does the operator come to the decision, and on what basis? A convincing argument can be made for both systems as to which is better. In general economic terms, mooring holds the best economics in the shallower water (up to about 5,500 ft) and more extensive, longer-term drilling plans. This would include development drilling.

On the other side, DP holds stronger economics for exploratory drilling in ultra-deepwater. In fact, it would be almost impossible, with today's technology, to drill in the ultra-deep without DP. However, this is just one facet of the argument. With new emerging technologies such as taut-leg and pre-set mooring becoming greater factors, the decision gets more difficult.

With all factors aside, such as location and water depth, some general cost comparisons can be made.

Installation comparisons

The installation costs of a DP system and a traditional deepwater mooring system for a newbuild drilling unit are close. DP is more expensive due to the fact that there are a number of regulatory requirements for system installation and more electronic components to install.

  • DP: The main cost for a DP system is the separate engine room, which is a regulatory requirement. The separate engine room is needed to power the thrusters and to provide backup in order to maintain position in the case of a fire or a flood, but this is more of a cost to the total rig construction than to the system.
DP also requires a much larger complement of electronic components as part of the control system, in addition to the installation of thrusters, larger fuel storage, and a more complex electrical system. These bump up the total price tag.

The costs also depend on the redundancy level of the system. The greater the redundancy level, DP Class 3 being the highest, the more equipment needed to be installed.

According to Randy Jones, Vice President of Nautronix, a leading DP supplier, "the control system is a very small portion of the cost. The main cost is the split engine room. The biggest cost on a vessel is engines and spinning electrical gear. A triple DP system runs $1-2 million, depending on how many position sensors are purchased with the actual control systems. This cost is only 0.3% of a $300-million newbuild vessel."

  • Mooring: A mooring system is not inexpensive either. Costs include winches, piles or anchors, chains, monitoring devices, as well as devices to locate and collect the anchors. Mechanical devices usually are less expensive than electronic devices, and there is no need for the additional engine room and fuel capacities. The installation of the mooring system is also an easier task and can save a bit of money in installation time.
Overall, according to industry consensus in the case of a newbuild, the short-term initial investment between the two systems makes the decision almost neutral. The DP is a bit more expensive, but not by a great deal. With a newbuild, contractors have the option to build the necessary requirements for DP or mooring into the overall design of the rig. This option provides greater cost equality between the two.

On a retrofit or upgrade, however, the mooring system is a superior choice economically. The addition of DP equipment to an existing rig requires a major overhaul, whereas the addition of a mooring system can be done with relatively minor modifications to the vessel. John Vecchio, Vice President of Engineering for Diamond Offshore concurs: "In a retro-fit, a DP system is very expensive. For a newbuild, they are pretty close to being in line."

Some vessel designs lend themselves to being a better fit for a certain system. Shawn Vigeant, Manager of Contract Services for Diamond Offshore provides a good example: "The Ocean Clipper made perfect sense to use DP. It was already self-propelled, met the qualifications, and had engine room support. We had to add some equipment to it, but it was more affordable. By putting thrusters on a normal rig, we would have had to add another engine room and more equipment. Plus, DP'ing a Victory Class rig, with 12 columns, would have been nearly impossible for a rig that size."

Maintenance comparisons

Economic differences are also a factor in terms of maintenance costs. DP uses computer programs. More precise, upgraded versions of the programs are being developed, and with each upgrade, the system must be changed at an associated cost. With steel mooring systems, steel upgrades are rare.

DP proponents do not feel the upgrading requirement is that great of a factor. Doug Foster, Operations Manager of Diamond Offshore's deepwater DP drillship, the Ocean Clipper, explains: "You can make software modifications between locations. It is like changing from Windows 3.1 to Windows 95. You don't have to take it to the shop for that. It can still be contained in that package."

In terms of maintenance, however, mooring lines require inspection each time the chain is hauled in and paid out, and adjustments are made during operation. This adds some expense to the operating cost.

Additionally, mooring equipment is traditionally easier to repair than components of DP systems. A winch is much easier to fix than a thruster.

Operating comparisons

The true economic difference between the two technologies begins to emerge once operations begin. In operations, the two technologies fall into categories of active and passive systems, which has a direct bearing on operating costs. DP is an active system, meaning that it is constantly running. When operating in full DP, the engine that powers the thrusters must remain in operation. Constant operation adds tremendous fuel costs to the operating expenses of a rig.

Mooring is a passive system. Once on line, the engines are not needed in constant operation. This is one of the greatest arguments made by mooring advocates, with respect to cost.

Fuel costs also play a significant role in the economics of DP. If fuel costs are very low and remain there, they could possibly spoil the economics favoring a moored rig in any circumstance. However, this is regarded as only a minor factor and highly unlikely.

Eldon Robinson, Technical Director of Delmar Systems, a mooring system provider, says that DP is a continuous cost. "Fuel costs for stationkeeping go on 24 hours a day, 7 days a week. You save fuel costs and maintenance, if you don't have to keep that system operating all the time."

Diamond's Foster suggests that continuous operation is not as big an impact as many think. "When we are on location drilling, we traditionally run three engines for DP and drilling. When we transit, we run three engines. And I have a feeling that most rigs, for their auxiliary plus their drilling drives, would probably not run quite as much. We are probably over by, just a guestimate, a third in normal weather. You do run full-time, but when I weigh it against a unit that is drilling with all of his mechanisms on-line, I don't feel that the difference is substantial."

At the same time, DP does not require the use of heavy-duty anchor handling boats and downtime to set anchors. The use of these boats can also eat into the operating budget and they must be used each time the rig moves location. This also brings up the availability of the vessels to handle anchors and the increased risk of something going wrong during the mooring setup.

But, does the fuel cost equal out with the cost of contracting anchor handling vessels? Peter Dove, President of Aker Marine Contractors, explains the cost of the process in this manner: "For conventional mooring, requiring two big boats, the contract rate for these is about $18,000/day, long term. and $30,000-35,000/day, if on spot. In addition, anchor crews and positioning equipment will probably cost $30,000, plus time." But, according to Dove, the operating costs are not that different, "The cost of the mooring system deployment, with four moves a year, is about the same as the cost of running a DP."

Time comparisons

This brings up the issue of time - setup and breakdown time and its associated cost for mooring systems, versus no setup and breakdown time with DP. A DP vessel offers the distinct advantage of being able to set position when it arrives on location and leave immediately. In contrast, the typical time to set up a mooring array is several days. This is what gives DP its advantage, one that compensates for the active system.

However, hookup time for a moored vessel is not necessarily lost time. Global's Keaton said, "Setup time for mooring is not lost. For example, after four anchors are deployed for the Glomar Celtic Sea, drilling can get underway. And, they've still got four more to set. If you've got your act together, you can make that time productive."

Delmar's Robinson added, "Not a lot of critical operations are going on, when you are mooring. When you are drilling, then you have critical operations."

However, the time gap between the two systems is beginning to close. The use of pre-set moorings in deepwater allows the mooring array to be prepared. The rig can hook up in a much shorter time. These pre-set moorings use such technologies as taut wire rope, suction pile anchors, and taut fiber leg systems. Pre-set moorings also allow a rig to extend into water depths similar to those of a DP-operated unit and reduces the variable deckload needed for the deepwater mooring systems.

Aker's Dove feels the only way to make the comparison with the DP system is with pre-set moorings. "For newbuilds in both cases, conventional mooring does not appear that attractive. If you are doing a newbuild, the money involved in all the mooring equipment is a big chunk.

"A water depth of 5,500 ft is the limit, unless you put thrusters on the rig. With thrusters, you can go up to 7,000-8,000 ft. After that, you are into pre-set moorings. With a taut-leg system that will control your watch circles, mooring becomes very attractive - economically and technically."

Diamond Offshore has used the pre-set moorings and agrees with the economical advantages. "We cut our teeth on upgrades and deepwater with EEX and the Ocean Voyager, using pre-sets. We really liked it a lot and it worked well," stated Shawn Vigeant, Manager of Contract Services for Diamond.

"We were able to go to much deeper water and not carry that deckload, and we could bring extra mud and riser without having to worry about carrying the mooring. If an operator will let you use the pre-set mooring, you can really extend the existing fleet. It's a lot cheaper," he said.

Transocean's Steddum said he supports the closing gap. "With pre-sets, you need some high-end stuff to install it. I think the gap, if there is one, between moored and DP, will close a bit as we get into the deeper waters where the pre-sets are more likely to be used. Pre-sets can also be used, when restricted on getting a pattern out."

Exploration vs development

The issue of time also adds another side to the controversy, maybe the most important side. With the cost of running the engines full time on DP, it is almost uneconomic to drill anything more than exploratory wells. This limits any DP-only vessel to an existence of exploratory drilling.

On the other hand, with the time involved for mooring, a moored vessel is geared towards development drilling. This is not to say that either type expressly limits the rig to that type of drilling. The economics tend to lean more toward that direction.

The issue then becomes whether DP vessels should be used for development drilling. There is more risk involved in this practice. Don Weisinger, Deepwater Technical Advisor for Vastar, said that DP can do development drilling, but there is a risk-cost exposure to providing for development drilling in the DP mode - especially if the rig undertakes well testing or completions.

"It depends on the operator's ability to assume risk. You can provide for development drilling and well completion with a DP vessel, if you are willing to assume the risk cost of that operation. Risk cost is determined by the reliability of all the systems involved and by the consequence cost, if the operator is not capable of securing the well in a catastrophic event. The cost of that event is part of the risk. If you, as an operator, are willing to accept that risk cost, then you can provide for development drilling and well completion on a DP vessel," he added.

Three other major factors involved in the debate are the problems of the deck space needed for a deepwater mooring system, the reliability of dynamic positioning, and operations during severe weather.

Space factor

A deepwater mooring system requires a very large variable deckload, whereas DP has no stipulation. Some operators require that the vessel be able to carry its own mooring system in order to reduce the need for boats. A much larger hull with a large variable deckload is needed to accommodate this capability. Another option is the need for large columns or lower hulls to save some of the deck space, however this is a very costly addition.

Diamond's Vigeant said that "with trying to carry 8,000-12,000 ft legs of mooring gear, the 4,000-5,000 tons of variable deckload all the sudden becomes 2,000-3,000 tons on a move. So, you must transfer the riser to a boat or dump mud."

"The Victory class upgrades we did were perfect for a mooring system because the hulls were big and stout, and perfect for the column sponsons and blisters. They already had a 3,000-ton load, and by adding those, we increased our deckload to 5,000 tons, even carrying our own mooring."

This is another aspect where the pre-set mooring systems increase the economics. With the pre-sets, a shallow water mooring system, or some smaller system, is used to save space. This is another instance of pre-set mooring bridging the gap.

Reliability factor

In the past, the strongest argument against DP was the occurrence of drive-offs. This is when, due to some malfunction of the DP system, the vessel powers off location, causing a possible disconnection of the riser and drillstring, and a loss of time. When a drive-off occurs, the implications can be catastrophic, especially if they occur during development drilling.

This brings up the element of redundancy. When trouble occurs with a mooring array, the majority of the time, critical operations are not underway. DP becomes vulnerable when redundancy is minimal. Robinson of Delmar feels that this causes one of the biggest splits between the technologies.

"If anything that keeps that vessel on location (DP) shows a problem, drilling must slow down to fix the problem," Robinson said. "Moored systems don't have those type occurrences. There are not a lot of critical operations going on when you are mooring. Drilling is a critical operation, and the vessel is at risk of losing mud and pipe in the hole if the DP system cannot maintain position." The difference (between the two) lies in the loss during operations."

At the same time, the risk of drive-offs remains low. The International Marine Contractors Association (IMCA) has done a study on the reliability of DP systems. According to their findings, a DP system sustains an average of 1.11 major drive-offs each year.

This sort of reliability shows promise of improvement in the coming years. The uptime of the newer systems being installed far exceeds that of the older systems, especially with triple redundancy.

Nautronix's Jones said, "I would suggest that over the last two years that the three DP suppliers have probably upgraded 75-90% of all the old DP systems on drilling units, and any newbuilds will have new systems on them. I think DP uptime is going to get better and better with the newer hardware."

Operators and contractors are fairly comfortable with the reliability of DP. Weisinger of Vastar commented: "It is still not as reliable as mooring, although conventional mooring does not offer 100% reliability. In relative terms, the DP systems we have today are very reliable, compared to the analog systems of the 1970s. The majority of the failures we experience today with the DP systems are not the DP systems themselves. They are the peripheral equipment - the data sensors, the satellites, or even to a large degree, human intervention failure."

John Barker, Deepwater Team Leader for Vastar added, "Even with all the improvements, mooring is still a slightly more reliable system than dynamic positioning - overall."

Weather factors

The third dispute concerns severe weather. When severe weather occurs, a moored vessel must disconnect or remain on location, compared with the ability, or necessity, of a DP vessel's movement to safer waters or a port. This is one of the true paradoxes of the debate.

Many in the industry pan mooring due to the fact that it requires extra time to pull anchor, disconnect, and leave location to avoid a storm. Proponents praise its ability to moor through even the toughest storms. For example, Global's Keaton praised the ability of the Glomar Celtic Sea to withstand the brunt of recent Hurricane Earl without a scratch.

On the other side of the coin, DP is panned for having to leave location to avoid storms, and praised for the ability to leave location to avoid storms. Mooring folk pan DP for the increased loss of time due to even the most minor threat of a storm. But proponents claim that it gives them extra time, allowing drilling operations to continue until the last available minute. DP also allows for other perks, when severe conditions exist.

Diamond's Foster said, "Recently when storms were coming up, we had our BOP's secured on the deck. We worked with our operator to stage our vessel on the edge of some of the storm forces to work with his logistical endeavors to transfer people, should it be required. That may sound lame in a drilling rig market, but it is a pretty cool functionality."

Operators and contractors have differing opinions on which system is optimal. And both recognize the need and importance of each system for certain applications. But, the operator still has the last word.

Operator preferences

Operators recognize the necessity for both systems, and the applications for different drilling plans.

BP currently has contracted for one semisubmersible drilling unit under construction, the Diamond Offshore Ocean Confidence, which will feature full DP. A BP representative explained the choice: "How do you do development drilling in 6,000 ft of water moored? I don't know of any moored vessels in more than 3,000-5,000 ft. In terms of the drilling plan in our current schedule, if you are not going to do DP, you are not going to do a lot of it."

Vastar's beliefs are supportive. Weisinger commented: "Our preference is for the type of positioning to meet the application. For exploration, from well to well in different areas, our preference is to be DP. It derives the most value from the expensive pieces of equipment that we have to use in ultra-deepwater. DP minimizes positioning time, and to some degree, transit time between locations.

"For development, we feel that the appropriate approach would be a moored vessel. And for the ultra-deep, we feel that the most efficient systems to create the maximum value for the operator and the contractor would be the pre-set taut mooring systems."

Contractor preferences

Diamond Offshore has a few different views on the preferred method. John Vecchio said, "If it is at all achievable, I would use mooring. This is because of smaller size of the crew, fuel economies, and comparable, if not preferable, capital costs. Also, there are fewer things to break (a thruster takes a lot more maintenance than a winch). In the Gulf of Mexico, I would prefer to use a moored rig, because historically we like to abandon the rigs in case of a storm. You cannot do that with DP."

But, Doug Foster, an experienced DP man with the Ocean Clipper supports DP. He said that DP "provides flexibility, maneuverability, self-contained operability, with minimal logistic support. You can do so many things with the rig."

Global Marine's Charles Keaton said "it depends on how long you are going to be on a spot for a period of time. Most people would prefer to have moored, because the operating costs, once it is moored, are much cheaper, and there are fewer uncertainties. The economics are really driven by the water depth."

"If you have a series of short wells, DP will pay for itself because you don't have the unmooring and mooring time," he added.

Transocean's Steddum says that the arguments are strong on both sides, with no clear cut winner. The only way to figure the optimal choice is on a case-by-case analysis. "It is fair to say that most operators come to that conclusion. I believe that if you can moor passively, that is what you would prefer to do, although it is not based entirely only economics.

"I think most operators themselves are convinced that it is cheaper to moor than to DP. You would DP in most cases where you cannot reliably put out a passive mooring system. We feel that in any drilling operation you can do moored, you can also do in DP. On a particular location, you can construct a study that will show a winner."

Optimizing the choice

Industry preference dictates that for shallower water, mooring is the optimal choice and DP for deeper water. For exploration drilling in deeper water, DP must be used and mooring for development. But what is the optimal setup?

It would seem the optimal setup would be a combination of both systems - specifically, a DP vessel with a shallow water mooring system that could attach to a pre-set mooring system.

Aker's Peter Dove explains: "New rigs should have DP and a shallow water mooring system, because you are not going to be able to do development drilling. A deepwater mooring system on a big semi would be about $30 million; if you just feature shallow water mooring, it will be about $10 million.

"The setting of a pre-set mooring system requires about 10 days, but it is off the critical path. Therefore, you have only the cost of the rig for one day. It takes no unproductive time. If it has to move to another location, you are leap-frogging to a second system. This is a two-day operation, which would take 10 days with a conventional system. This is one day more than with a DP. With pre-set mooring, you can use third and fourth generation rigs to do what DP can do. The cost is $300,000 on a newbuild, compared to $30,000/day with pre-set mooring. Productivity is down a little, but costs are down tremendously."

Weisinger agrees with the concept, but not with the idea of the direct application of a shallow water mooring system.

"We will have rig-side equipment capable of attaching to the pre-set system. It must all be sized appropriately to provide for adequate stationkeeping capability."

"Taut fiber-leg mooring systems may be the only way we can economically provide for mooring capability in ultra-deepwater for development drilling and completion operations. If you are not willing to accept the risk for DP, then that is certainly the only way to go now," he added.

The optimal solution appears to be a combination of the two systems to maximize the advantages of both, if not to keep everybody happy.

Future systems

Several ideas have been suggested for the future of stationkeeping. Some are being tested in deepwater today. On the mooring side, fiber taut-leg moorings, suction pile anchors, and other such equipment will be used in combination with the concept of pre-setting mooring arrays.

For DP, Nautronix suggests DP with all the risers in a disconnect format, where the disconnection point is at the surface or subsurface. This provides a flexible production riser bundle coming up beneath the vessel that can be broken at that point, rather than hanging a complete riser from the ship with the detachment point on the seabed.

Nautronix also forsees DP being used on FPSOs. Jones said "the trend is fully DP'd FPSO's. If they find oil in 7,500 ft water depths, moorings will not be economical. How can you carry all that chain and anchor on deck and have room for oil and production capability. We are already at the limit when drillships carry riser and DP for 900 ft water depths. So how do you put chain and anchor on those as well?

"You reach a limit to where we put aircraft carrier size units out there," Jones said. "We are already pushing the envelope with thruster sizes now. All the new drillships are double-hull design that are capable of conversion to production and they have no chain and anchor on them for mooring spreads."

But technical development for both concepts is not slowing down. Several companies such as Vastar and Shell are using the pre-set mooring system in the Gulf of Mexico, and several deepwater vessels are under construction that will be moored in deeper water depths.

Nautronix Jones disagrees. "We will not be seeing more deepwater mooring systems. The DP systems that we are selling - for drilling vessels and production vessels - is skyrocketing. The numbers don't lie."

Dynamic positioning companies are indeed thriving. Nautronix has sold more DP systems this last year than Honeywell's DP division did in the company's whole 15-year existence. Kongsberg Simrad has also reported orders for 30 vessel systems so far this year. All the deepwater drillships under construction will be fitted with DP and a large number of the semisubmersibles

So the battle continues, with neither side showing signs of weakness. Only time will tell what the best way is to hold steady in the quest for oil.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.

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