Versabuoy - White Paper

Versabuoy – Dry Tree Technology for Marginal Fields
John Greeves, Technical Director, Versabar Inc.



The Versabuoy floating platform technology represents a new class of deepwater development system. It responds to wave loading in a fundamentally different way when compared to the existing suite of technologies, which in turn results in a different set of performance characteristics. Although the technology is “new”, it is simply achieved through a unique arrangement of existing components and hardware all with established performance track records.

This paper will describe the Versabuoy system, capture its unique attributes and provide a commercial framework for assessing its potential application in the Gulf of Mexico deepwater developments, including marginal opportunities.

Established technology delivered in a new configuration

Figure 1 illustrates an example Versabuoy platform configured for full API rig platform drilling with a 3x3 central moon pool supporting up to nine surface trees, top tensioned risers. In this depiction the conventional open truss configured topsides is supported by four independent buoys, each buoy connected to the topsides by an articulating connection. This connection decouples the buoy pitch and roll motions from the topsides and from each other. Each buoy is intrinsically stable and has a GM value typically in the range of 25 to 50 feet. The buoys have no connections between them below the water line. The taut leg mooring lines and catenary risers attach directly to the deck, facilitating installation and in-service inspection and maintenance as required.

There is no element of the system that has not already been deployed in an operating system of one type or another. The most unique component is the articulating connection detail between the buoys and the topside (or the “joint”), which has been subjected to US Coast Guard and Class Society review and approval through the deployment of the Versabar twin-gantry marine heavy lift vessels the VB-4,000 and VB-10,000.



The VB-10,000 incorporates two 5,000-ton capacity joints, similar to the size required for a typical Versabuoy platform.  The joint design has been subjected to over 5 years of operating service on the VB-4,000 and VB-10,000 vessels. The design includes a double joint configuration which provides 100% load path redundancy, in turn facilitating the removal, inspection and replacement of any component of the wear surface while in-service.



Figure 3 shows an example of a fully redundant articulating connection. The main wear surfaces and support pins within the connections currently in service on the lift vessels are removed for inspection on an annual basis. The synthetic bushing material used on the key wear surfaces has an excellent operating history, with no replacement yet required,  and is a true “plug and play” material, requiring no maintenance or lubrication during service.

The Versabuoy technology has been developed and refined through multiple engineering studies and scale model test programs. The introduction of the connections between the buoys and topsides results in a multi-body class numerical analysis problem, where the individual bodies are able to move independently of each other in one or more degrees of freedom. Specialist tools (WAMIT, AQWA, and SESAM) have been available for 5 years plus, allowing for independent engineering assessments to be performed. The extensive model test program completed has provided a large database of multi-body test results under a wide range of loading conditions, and which has been used to benchmark and validate the various analytical tools used.



Figure 4 shows a Versabuoy platform undergoing testing in the Gulf of Mexico 100-year hurricane wave conditions. Table 1 presents a summary of key response parameters measured during the model test program. A key attribute of the system is the low topsides motions experienced even under extreme hurricane storm conditions. These low motions support another unique operating capability of the technology, that of being able to rigidly (simply) connect two or more Versabuoy platforms together to provide very large offshore platforms (or bases), or a phased development approach where additional platform modules are combined during the life of the development . Figure 5 shows a two-module configuration (two 250ft by 250ft topsides each with 4 buoys, 8 buoys total) during the 1,000 year hurricane conditions. The model test results confirm connections loads well within structural capacity of standard padeye details, and combined system motions better than for single modules.

More for Less (new technology is not always more expensive)

So what can we achieve with this technology? In order to be adopted it must offer technical and/or commercial benefits when compared to existing options.



Figure 6 presents a graph for all spar platforms developed in the Gulf of Mexico through 2009, showing topsides payload against fabricated hull weight (excluding solid ballast). The ATP Titan platform (MinDOC design) is also included for reference purposes as a spar type platform. The traditional spar platform population can be broadly split into two segments; those that support full platform drilling operations (population of four platforms in the Figure), and those which support workover rigs and/or full production capacity. The primary operational difference between these two segments of the spar population is the amount of topsides payload supported by the spar hull, the effects of which are clearly seen from the step change increase in fabricated hull weights for these higher payload platforms. If this plot were extended to show total hull displacement (instead of structural hull weight) this step change would be even more exaggerated due to the increase in solid ballast requirements needed to maintain the required GM values for spar platforms.

The parameters for a full API rig drill-capable Versabuoy platform are plotted on the same figure for comparison. The system payload of 17,500 tons is at the lower end of the four fully drill-capable spars, but the reduction in fabricated hull steel is significant (17,000 tons of Versabuoy platform hull steel versus 28,000 tons for the equivalent spar). This performance improvement is a direct result of the introduction of the articulated connections between the buoys and topside. The point of applied load on each Versabuoy hulls is fixed at this connection point (approximately 50 feet above MSL). This results in much lower solid ballast requirements for the Versabuoy system, and lower hull bending moments. Each Versabuoy hull deploys only 2,000 tons of solid ballast per hull.  From this comparison, therefore it appears that the Versabuoy technology offers a more structurally efficient solution where fabricated hull weights and solid ballast amounts are considerably less than for other platform types. A further simplification is that the Versabuoy platform hull fabrication is divided equally into four (for this example) identical buoys, each now with a fabricated weight of 4,250 tons. There are a large number of regional fabrication facilities capable of building structures with a weight of 4,000 to 5,000 tons (typical of mid-sized fixed jacket type structures), compared to those capable of building single piece hulls in the weight range of 20,000 to 40,000 tons.

The lower system displacement requirements combined with multiple smaller hulls also offers simpler construction details.



Figure 7 shows a typical Versabuoy hull arrangement. It follows a traditional configuration with a hard tank (with variable ballast tanks included) with spatial separation to a lower weighted section to provide the desired GM. The hard tank is now fabricated from rolled tubular pipe sections of a diameter of 19 feet or less. This is the largest diameter which can be rolled from a single sheet of steel plate. The hard tank sections are stabilized against hydrostatic collapse through the use of internal ring stiffeners located on 6 feet centers. These ring stiffeners also act as inspection galleries. Each hull has a cross sectional spacing between the vertical legs of between 40 and 50 feet, again small in comparison with other structure types. The majority of fabrication and assembly can be completed at ground level and “rolled up” just like a tradition jacket structure for final assembly.

In summary, not only does a Versabuoy platform require the fabrication of less steel, it also uses very simple fabrication details which result in lower fabrication rates. The increased number of (local) fabrication facilities which can compete for the fabrication of the hulls adds a further level of cost control through competition.

An assessment of cost competitiveness could not be complete without the consideration of platform installation options. With the exception of the Kikeh platform offshore Malaysia, Spars have historically required the use of a Heavy Lift Vessel for the topsides installation. Foundations, hull transport and upending and mooring line installation and hook-up can all be completed using other non heavy-lift assets. Based on current practices larger platform installations (i.e. those that are drill capable) are going to need access to one of the three large international semi-submersible heavy lift vessels.

As with the Red Hawk spar, the Versabuoy hulls can be transported offshore with the solid ballast already installed. Final upending is simply achieved through sequential hull flooding. A Versabuoy platform topsides installation is achieved through float-off of the topsides following hull upending and positioning under the deck on a transport barge. Hull ballast control is achieved using compressed air provided from topsides installed equipment. Platform installation by local marine contractors is therefore now feasible using locally available assets and resources. Costs will reduce due to both the use of lower cost assets and local competition, and scheduling issues associated with accessing major international assets will be eliminated.

The business case for action – do more for less

Prices are up! Between 2003 and 2010 upstream commodities (materials, labor etc) have inflated at a normalized annual rate of approximately 14% per year. Deepwater capable drilling day rates have increased from $125,000 per day to in excess of $500,000 per day. New Gulf of Mexico requirements for BOP’s used for floating platform drilled wells also further serve to limit rig selection and maintain higher prices for Gulf of Mexico deepwater drilling.

In 2012 prices of typical deepwater Gulf of Mexico development options with associated costs (including drilling) are as follows:


Development Type


2 to 4 well subsea tieback to existing platform

$600 to 800 Million

6 to 8 well subsea tieback to new build production platform

$2,000 to $2,500 Million

Dry tree class drilling and production hub

$3,000 to $4,000 Million

Lower Tertiary reservoir hub class  Development

$4,000 to $8,000 Million


The average Gulf of Mexico field has a STOOIP volume of 90 Million BOE – just about sufficient to support a minimum subsea tie-back to an existing platform. Each successful exploration well finds an average reservoir volume of just under 30 Million BOE.

The “old” Gulf of Mexico deepwater fields (Neogene age reservoirs) exhibit base case Ultimate Recovery factors (UR’s) of between 30% and 35% of STOOIP. Improved recovery techniques such as water injection, gas lift or well bore pumping can improve UR factors to 50% of STOOIP. Additional well sidetracks and recompletions can access up to another 10% to 15% through accessing “stranded” reservoir sections. The “new” deepwater (Paleogene age reservoirs) appears to be “gifted” with UR’s closer to 10% of STOIIP. Drilling challenges for these “new deepwater” wells are considerable due to drilling to very deep TVD (25,000 feet plus), and drilling through salt and into reservoirs with high pressure and temperature. Given successfully drilled and completed wells some form of improved recovery technology will almost certainly be required to boost production rates and recoverable volumes. Very limited development data is available for these “new” Gulf of Mexico deepwater developments, but early indications are that we can expect costs of between 150% and 200% of established deepwater norms.

Low cost access to Dry Tree technology

Dry tree development systems provide an excellent development tool for deepwater fields. They significantly reduce initial drilling costs, greatly reduce life of well costs including sidetracks, and significantly reduce the cost of delivering improved recovery solutions. Their downside has been the significant increase in development capital required to fabricate and install a floating development capable of supporting drilling and the deferment of initial production when compared to pre-drilled subsea developments.  A technology which supports platform drilled and completed wells at a lower cost than current solutions, such as Versabuoy, could therefore be expected to offer attractive development options for upcoming deepwater developments.


Figure 8 presents estimated  total development costs against well count for (1) a subsea tie-back to an existing host, (2) a drill capable spar platform with dry tress, and (3) a Versabuoy platform development using platform drilled and completed wells. Versabuoy platform costing has been based on local Gulf of Mexico fabrication pricing and installation using local Gulf of Mexico construction assets. Platform drilling operations have been priced using existing floating platform capable drilling rigs. Clearly the low well count cases for the option (3) in Figure 8 are unrealistic, but this option serves to establish an upper bound on development costs.

Figure 8 now highlights a new set of development options based around a lower cost dry tree platform technology. For a total of four development wells a Versabuoy dry tree platform has a capital cost equivalent to a subsea tie-back development with MODU drilling. When life of well issues including sidetracks, the ability to add improved recovery solutions from a platform with surface completed wells, and the potential for platform redeployment and reuse are considered the dry tree development option becomes even more attractive. Extending this analysis, larger subsea developments with multiple drill centers could replace each subsea drill site with a low cost dry tree development. Each dry tree platform could include a reduced amount of full processing and dispense with a central hub platform, or each platform could use limited processing and still tie into a central gathering station. Dry tree solutions remove flow assurance issues and provide options for distributed water injection, gas lift and wellbore pumping.

Table 2 presents the results of screening economic assessments for three development options, all based on a Gulf of Mexico deepwater reservoir of the average find size (90 MMBOE). The economic model uses a full discounted cash flow analysis accounting for OPEX and WELLEX costs over the life of the development based on the number and type of wells drilled and the sequence of drilling (i.e. platform wells being drilled after the platform has been installed). Screening is performed assuming a flat oil price of $70 per BOE and a discount rate of 10% with full royalty payment (i.e. assumes no royalty relief) and normal US corporate tax rates. All financial parameters are normalized with respect to the three well subsea tie-back case.

As would be expected the 3 well subsea tie-back case meets normally acceptable economic thresholds (based on the Value Investment Ratio which is defined as the ratio of NPV discounted cash flow after tax to NPV CAPEX). The three well Versabuoy platform option recovers the same cumulative discounted cash flow, but requires an initially higher capital investment, and so has a lower VIR. Note that the use of surface wells result in a slightly higher ultimate recovery and associated production rate, and lower life of well costs. At the end of the field life (10 to 15 years after first production) the Versabuoy platform offers the chance for relocation and re-use for a similar development (which has not been accounted for in the economic model). The third case presented is the three production well Versabuoy platform development, enhanced with local water injection. Capital requirements are increased accordingly to account for the extra drilling and facilities costs, as are the ultimate recovery factor and production rates. The economic parameters for this development option are considerably improved when compared to the others, with a doubling in VIR. This case serves to further demonstrate the operational versatility and associated economic upside of a dry tree development even for what is considered to be a marginal development.



Gulf of Mexico deepwater developments continue to cost more due to general commodity pricing pressures and increasing technical challenges, while potentially producing less per well due to lower reservoir productivities. Improved recovery methods will become increasingly important and probably the norm in future deepwater development.

Given such a scenario platform drilled and completed well developments offer multiple advantages, primarily around reducing well costs, and improving recovery factors through the support of enhanced recovery technologies such as surface water injection and well bore pumping. Historically the capital costs for deepwater capable platforms able to support platform drilling and dry trees have not tipped the general development balance in the favor of this solution except for the largest of fields.

A new class of floating development platform (the Versabuoy technology) offering lower cost platform drilling and completed wells is available. Lower costs are achieved through system efficiencies due to unique performance characteristics (less fabrication required), simpler fabrication (lower unit costs), increased local fabrication yard choice (price reduction through competition), and installation using regionally available marine assets. The lower cost platform technology presented offers operators new development options which can mitigate development risks and improve economic performance.

New Technology adoption can only happen when the outcome of using it is better than the status quo, but when it does it needs to be seriously considered.







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