The integrated spar upper hull arrangement. (Image courtesy of Technip)

The spar has been a reliable deepwater production option since 1997, when Neptune made its debut as the first spar installed in the Gulf of Mexico. Now, an innovative modification of the established design has adapted the spar for drilling.

“Everything that has been done so far has been based on the traditional spar design concept, which consists of a hull that supports production topsides and a drillset,” explained Terje Eilertsen, senior project manager, Technip. “To date, improvements have taken an isolated approach, focusing on the hull or the topside or the drillset. Until now, that has worked very well, but as we move to deeper water, we are running into a completely new set of rules.”

Playing a new game

For starters, Eilertsen said, there is the need where enormous sub-salt plays in ultra-deep water areas like Keatley Canyon and Walker Ridge require wells with measured depths of 38,000 ft (11,590 m). The wells will likely call for complex completions, which will necessitate an enormous number of tubulars onboard. These tubulars, which have to be handled from the beginning of grassroots drilling through completion, can weigh as much as 18 million lb. A small segment of mobile offshore drilling unit (MODU) meet the depth and weight requirements, and their availability is very limited.

Deepwater wells require fifth or sixth generation rigs that have a minimum hook load of 2 million lb, Eilertsen said. “And if you want to be efficient, the MODU has to be able to handle a setback load of 2.2 to 3 million pounds.” The problem is that these rigs are not readily available, and those that are available are being leased at premium rates.

The cost of drilling, completion

Drilling and completion make up the largest percentage of the cost of carrying out a deepwater high-pressure/high-temperature (HP/HT) project. With the cost of the MODU factored in, Eilertsen said, drilling and completion make up 65% to 80% of total project cost. “The topside, hull, and mooring components are not large in terms of investment. If you are going to try to reduce project development costs, the most effective place to make significant reductions is on the drilling end.”

Although HP/HT wells have extremely high pressure at the outset, the depletion of the pressure is relatively fast, Eilertsen said. “Within five to seven years, there is normally a need for artificial lift to sustain production levels. Sidetracks normally have to be drilled as well in the course of field development, and that adds more cost. What we see is well costs hitting $250 million plus over the life of the field.”

Dry trees

Technip believes part of the answer to lowering drilling costs is in the use of dry completion systems.

“We see workover costs as a major difference between using a dry tree or a wet tree because of the cost and complexity of performing well interventions. We believe you get much better reservoir performance and hence recovery when you can do well intervention as it is needed, which is easier to execute and less costly with a dry tree than with a wet one.” Eilertsen said.

Eilertsen pointed to Minerals Management Service data that indicates what he called, “a clear picture of much better recoverability over the lifetime of a field” where dry completions are used. “Recoverables can be 20% to 25% greater.”

With a dry tree, there is no wet blowout preventer, which reduces marine operations. Another plus is that with a dry-tree riser system, there are no drilling riser flex joints. “We use stress joints, and the window for operating the drill string is normally based on the angle of the stress joints. The controlled geometry of the tapered stress joint therefore expands the operational window for drill string rotation,” Eilertsen said. The dry tree also allows a simpler completion than a wet tree, which takes 20% to 30% less time to execute.

Downtime costs resulting from hurricanes and loop currents in the Gulf have become serious operating considerations as well. The new drilling and production spar is designed to post-Katrina conditions and will be permanently moored so that it does not have to move off station in the case of inclement conditions.

For 2006, abandonment costs for wet-tree MODUs operating in the Gulf of Mexico averaged $50 million, while dry-tree drilling unit abandonment costs over the same timeframe totaled about $10 million. “There is a $40-million gap on those two components alone,” Eilertsen said. “For sub-salt wells in the Gulf, drilling will take place over seven or eight years. And then there are workovers that will go on for the life of the field. Over a 20- to 25-year field life, you’re talking about an enormous amount of money.”

A new option

The concept for the drilling and production spar came from Technip’s focus on cost reduction.

“Drilling is the main driver,” Eilertsen said, “and drilling is also a tool for completion. We had to have a drillset that can accommodate setback and hook load requirements that are beyond anything that exists today.”

A traditional spar does not have enough real estate to accommodate a drillset; so Technip took the design in a different direction. The new unit is a three-deck spar with a drill set on top. The drillfloor is 50 ft (15 m) lower in elevation than the traditional spar’s top deck, which brings down the vertical center of gravity, allowing for the installation of a 200 ft by 90 ft (61 m by 27 m) piperack with a 2,000-metric-ton capacity for tubular storage. The upper deck accommodates living quarters as well.

“We sized a 5,000-metric-ton skiddable drillset that we believe is within 90% accuracy of what is required to drill subsalt wells in the Gulf. The new spar will have 2-million-pound hook load, 2.5-million-pound setback load, and will carry more than 60,000 ft (18,300 m) of tubulars,” Eilertsen said.

One of the unique features for the spar riser design is the possibility of having the drilling riser permanently deployed for the duration of the drilling program. In the case of performing grass roots drilling, the drilling riser will be connected to a subsea parking stump, Eilertsen explained. The drill set will be positioned over the dedicated moon pool slot so that openhole drilling operations can be performed.

Where the hull in a traditional spar is empty, the drilling and production spar houses circular bulk storage and mud tanks. “We’ve filled up the upper portion of the hull with bulk cement and barite tanks, reserve mud tanks, and completion tanks. It is just as efficiently arranged as any sixth generation MODU. In fact, the interface between the topsides and hull is minimal compared to a tension-leg platform or MODU, which will have a huge effect on commissioning and integration offshore, Eilertsen said.”

The mud system consists of four 2,200-hp pumps with 7,500-psi capability. “Premixed mud and mud boost are important for deepwater drilling. That requires a dedicated pump for mud boosting and at least 8,000 bbl of premixed active mud. We’ve provided for an additional 30 Mcf of bulk mud so we can readily mix another 8,000 bbl, which will allow the spar to contend with eventualities such as lost circulation,” Eilertsen explained.

The drilling and production spar topsides has an operating weight of approximately 30,000 metric tons. Including top tensioned riser load increases the facility payload to approximately 60,000 metric tons. “No other dry tree drilling unit is anywhere close to this size,” Eilertsen said.