Ten years ago, when the deepwater Gulf of Mexico started to take off, the primary focus of project teams was to shave off as much of the capital cost as possible, assuming that the reservoirs were well understood and that there was a deep and liquid market for drilling rigs. The central challenge was how to apply new technologies with the low price regime that was prevalent at the time.

The next phase of deepwater development faces very different challenges. The drilling market is tighter, wells are much deeper, seismic information for the reservoirs is of much lower quality and capital costs are higher. New integrated development systems and associated business models are required in order to confront these new commercial realities.
Ed Horton, chairman of AGR Deepwater Development Systems, believes the industry needs a new paradigm. Flexible units available on a leased basis that can drill, produce and relocate will form an enabling technology to address these challenges. The development team at the company consists many of the same people who assisted in the development of various generations of the spar technology.

Gulf of Mexico frontiers
The most exciting reservoirs found in North America over the last few years are the very deep reservoirs that have been discovered in the Lower Tertiary and deep Miocene plays in the deepwater Gulf of Mexico. A number of discoveries have been announced in these trends over the past few years, many of which have large structures but are fairly complicated and poorly understood. In addition to the inherent complexity involved in such great water and well depths, there are still major questions about well deliverability and various production requirements.

Although seismic imaging at such extreme depths is already a difficult problem, further complicating the issues in these reservoirs is the fact that the vast majority of them are below the salt canopy, which distorts the seismic imaging. Most of the deepwater projects that have been completed to date are on the fringes of the salt canopy, whereas many of those currently under consideration are directly below the canopy. Reservoir understanding will be significantly poorer than has been the case on deepwater projects to date, enhancing the value of flexibility in the development systems.

Further complicating the picture is the fact that technical requirements for these systems will be significant, driven by the extreme pressures and temperatures that are expected as well as the requirements for various maintenance activities on the seafloor, including workover, sidetracking, flow assurance work and boosting.

Nearly all of these fields happen to be out in the main loop current alley, where the stronger currents persist for much of the year. As one operator has said, “So far we have been working where the loop visits every now and then. Now we are going to have to work where it lives.” The persistence of these strong currents has disrupted many of the drilling programs close to that area, decreasing productivity and increasing costs.

Strains on tradition
To date, project evaluation methods that have been used for deepwater projects have been based on the same methodologies that have been used for many years in the shallow water and onshore, which do not address the fundamental investment drivers. The massive development of shallowwater resources over the last 30 years has been characterized by high-quality seismic data (improving over time), cheap appraisal wells and large fixed investments which cannot be relocated. The costs involved in project delivery were dominated by the capital cost component of the project, which was why the oil companies built their processes around seismic surveys and drilling appraisal wells until the uncertainty could be reduced to the point that the fixed costs could be justified.

The next round of major capital projects in the deepwater Gulf of Mexico will be far more difficult than the first because the vast majority of the attractive prospects are deep and below the salt canopy. Combine these conditions with the high day rates for mobile offshore drilling units (MODUs) and it is clear that the traditional development paradigm is strained to its limit. The amount of certainty that is traditionally sought with good seismic data and 8 to 10 appraisal wells is economically infeasible when well costs approach US $100 million per well. Given the depth, the lack of analogs and the poor quality of the seismic work, the previous level of certainty may not be achievable.

In the next round of developments, the drilling costs will represent a much more significant portion of the total expenditure, by some estimates making up 70 to 80% of the total. Development drilling times are also extending, with some projects requiring 4 to 5 years of drilling. Combining the high drilling costs and the reservoir uncertainty, phased developments using platform drilling appears to be very attractive.

Flexible units
Having witnessed the formation of contract drilling as a third-party business, Horton imagined a number of years ago that the next major step in deepwater offshore facilities would involve technologies to make the units more flexible and enable an easy redeployment for a second use. Although the leased floating production, storage and offloading vessel (FPSO) market has existed for many years, floating drilling and production systems have typically been tailored to the specific needs of a particular reservoir.

During his career, Horton has been involved in many of the major developments in offshore technology, starting with the Mohole project, where the main technologies involved in floating drilling were developed. He has also developed the original patents that laid the foundation for nearly all floating drilling and production systems operating today. His inventions have been enabling technologies for development of deepwater reservoirs for many years.

Deepwater development systems are characterized by significant interactions between components, and major breakthroughs are therefore often the result of combinations of several incremental technical advances built on established technologies. Horton’s newest development system innovation, the multicolumn floater (MCF), provides many of the main benefits of spars, tension-leg platforms (TLPs) and semisubmersibles while maintaining the inherent simplicity of the spar systems. To paraphrase one of our clients, in a world of unknown unknowns, there is less not to know about simple systems.

The MCF development system comprises a deep draft semisubmersible with a surface blowout preventor (BOP) drilling system combined with an efficient, rapid-acting mooring tensioning system that is used to tension a permanent mooring system designed to withstand extreme storms. The design also includes a vertically restrained welldeck for supporting risers and flexible topsides, installed using a floatover deck at a near-shore location. This combination of features provides a system that can adapt to a range of conditions including expected ranges of fluid types, riser numbers and specifications, water depths, and metocean conditions.

The floating system itself consists of a pontoon base that connects four columns together. In order to achieve good vertical motions that are sufficiently benign to support vertical and steel catenary risers, semisubmersibles must be designed to have a deep draft. Typical semi-submersibles are, however, limited in draft by the fact that the topsides are installed quayside and the floater must be stable while maintaining a desired tow-out clearance, which is typically on the order of 40 ft (12 m). By installing the topsides using a simple offshore floatover operation, similar to that performed for the Kikeh spar in Malaysia at the end of last year, the draft can be much larger than the roughly 100 ft (30 m) that can be achieved in a normal design.

The MCF is different from a typical semisubmersible in that all of the buoyancy is provided by the columns, and the pontoon is flooded during normal operation. Using this system, the design is much more stable than a typical design. Additionally, the compartmentation that is used is much more redundant than that of a typical semisubmersible. Each column consists of a series of four cells, each with three compartments, for a total of 12 compartments per column. The pontoon provides buoyancy during the towout operation but is flooded prior to installation of the topsides.

The ballast systems are much simpler and safer than those used on a typical semisubmersible. The design uses an air-over-water ballast system, similar to that used on several of the classic spars as well as the cell spar design. This design provides significant additional safety and redundancy as well as simpler operations and maintenance.

The vertically restrained welldeck (VRW) consists of a large central buoyancy can that is used to support vertical risers, which can be either the traditional dry tree vertical risers such as those used on spars and TLPs or direct vertical access (DVA) wet trees which are placed within the mooring pattern of the MCF. The VRW comprises a series of cellular columns, built using the same fabrication methods used for the MCF columns, structurally connected together with a number of riser slots that penetrate through the main body of the buoyancy can. These outer slots are used to deploy a variety of riser types that can be configured specifically for each project without any requirement to modify the buoyancy can for a second-use application.

An additional feature of the VRW is a riser system that allows production flow lines to be deployed in a bundled vertically restrained conduit tied to the seafloor. Each production flow line is independent, which means that lines can be accessed, added and pulled individually without affecting other risers. At the base of the conduit are jumper lines that can be attached to either subsea trees that are placed within the mooring watch circle for DVA or to pipeline end terminals that connect to satellite wells. Use of this system allows significant well construction and maintenance advantages compared to standard wet tree development paradigms while maintaining relatively simple interfaces to the vessel. This system also allows the design of the seafloor systems to be decoupled from the design of the vessel, which means that the surface facility can be replaced without requiring modification of the seafloor systems.

The drilling riser is supported on the top of the VRW, where it is located within a central riser slot. The MCF drilling system is similar to that used for previous spar and TLP projects and is based on the simple surface BOP systems that have proven to be successful over their many years of service all over the world. The surface BOP is particularly advantageous for very deep water and adverse metocean conditions, since all complicated mechanical equipment is on the surface and therefore allows much simpler well control and no subsea BOP or lower marine riser package (LMRP) tripping. Once the pressured drilling riser is landed, the drilling operations are relatively insensitive to loop currents and active storms. Surface BOP drilling systems in the deepwater Gulf of Mexico have had minimal metocean-driven drilling downtime, whereas the subsea BOP systems have had significant interruptions for hurricane abandonment and loop currents.

Surface BOP systems have been successfully deployed from MODUs and have demonstrated significant drilling economic advantages in both the Far East and Brazil, where metocean conditions are relatively benign. Using this type of system in the Gulf of Mexico requires favorable vertical motion characteristics in storms combined with a permanent mooring system as opposed to a typical MODU mooring design.

Supporting the drilling riser from the VRW ensures that vertical motion of the surface BOP in even the worst of storms is negligible. The MCF mooring system is designed around the same philosophies that have proven to be successful on spars to date, although modified to enable rapid connection of the lines once the vessel reaches the final deployment site. The onboard mooring systems are designed to perform the connection and tensioning work rather than requiring the use of additional temporary winching arrangements. Using this system, the MCF can be storm-safe within a period of a few days rather than the weeks of exposure that is common to many of the facilities deployed thus far in the deepwater Gulf of Mexico.

The platform is designed to be installed and relocated using the services of a multifunction pontoon barge (MFP), which can be arranged in several configurations to accomplish a wide variety of offshore construction tasks. The MFP will be a Jones Act barge that can perform the topsides floatover installation and can also perform the mooring installation operations as well as some subsea construction. In today’s tight market for the specialized vessels required for offshore construction, projects must be designed around the capabilities of the specific construction vessels that are available. Use of the MFP reduces dependence on these specialized vessels, greatly enhancing project execution.

Currently two MCF designs are being prepared to meet different functional needs in the deepwater marketplace. Production and drilling systems for the first vessel are similar to those used for many of the workover and completion spars to date, including 40,000 b/d of oil and 200 MMcf/d of gas combined with a heavy workover and completion rig. The second vessel is designed to have a similar process train to the first vessel but have a full drilling rig, providing an excellent system for early reservoir evaluation because the unit can drill the development wells as well as produce.

The main interfaces with the seafloor are the same for both vessels, allowing execution plans that involve first deploying the full drilling unit for early reservoir testing and subsequent development drilling and then replacing this unit with the smaller unit for the remainder of the life of the field. The vessels also allow the flexibility to add or remove process trains as required for the first field as the reservoir is better understood as well as on subsequent deployments.

The true test will be when these MCF platforms are put out into the field. However, in the high-pressure/high-temperature environment that appears to be more prevalent in the deepwater Gulf of Mexico, use of this type of facility will greatly improve project economics because project cycles can be shortened, cash flow is enhanced and the unit can respond as reservoir understanding grows over time.

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