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1. One of the differences between Spar and TLP is that its centre of gravity is always lower than the centre of buoyancy. This makes the Spar unconditionally stable.

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Difference between Spar and TLP

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FLOATING PRODUCTION UNITS

According to French et. al (2006), approximately one-third of the active deepwater drilling rigs working in the Gulf of Mexico in 2005 were aboard Floating Production Units, although some of these rigs were engaged only in well completion and workover services rather than full drilling operations. Wells drilled from FPUs are much more likely to be development wells than exploration wells.

Four types of FPUs are now being equipped for drilling as well as for oil and gas production operation:

Semisubmersible floating production systems (FPS) of several designs

Ship-shaped (monohull) Floating Production, Storage, and Offloading systems (FPSOs)-when equipped for drilling, the abbreviation FPSO becomes FDPSO or FPDSO

Tension Leg Platforms (TLPs)

Spar platforms.

Each type of FPU has its unique characteristics as a drilling platform, and these will be described below. But they also share several characteristics that are not commonly associated with drilling from MODUs.

The majority of wells drilled from FPUs are producers or injectors, and they are thus completed with the appropriate downhole equipment and a production or injection tree. Exploration wells, drilled mainly from MODUs, are not completed, although they may be suspended and completed later for production or water/gas injection. MODUs do, however, drill production and injection wells for subsea completion and tieback to an FPU or a bottom-founded platform, and the completion work is done by the MODU.

An FPU-based rig drills through a large template placed on the seafloor beneath the unit ( Subsea template and manifold during systems integration testing (SIT). Courtesy of Oceaneering International, Inc.). These templates contain a series of slots through which the wells are drilled. With FPSOs and FPS's, the wells are completed subsea and the production tree is installed on the template, which then also contains piping and remotely operated valves to manifold produced fluids and regulate flow. With TLPs and spars, the wells are completed aboard the platform using a surface tree. The methods of initiating, or spudding, a well and completing it from a TLP or spar thus differ from those used with FPS's and FPSOs. (Under many field development scenarios using an FPU, a MODU drills some or all of the wells through one or more subsea templates, including the template located directly beneath the FPU.)

Wells drilled from FPUs are far more likely to be directional than those drilled from MODUs, which typically are positioned directly above the reservoir target. While FPUs can be repositioned within certain limits to achieve vertical alignment with a particular slot in the subsea drilling template, most of the reservoir targets lie at some horizontal distance from the template and the FPU's location, and can be reached only by drilling the well at an angle. These directional wells sometimes achieve horizontal departures of more than four miles from the FPU's location, and well angles of 75 to 90 degrees from vertical are not uncommon. In fact, in April 2007, Exxon Mobil reported that

"Exxon Neftegas Limited (ENL), has completed drilling of the Z-11 well, the longest measured depth extended-reach drilling (ERD) well in the world. Located on Sakhalin Island offshore Eastern Russia, the record-setting Z-11 achieved a total measured depth of 37,016 feet (11,282 meters) or over seven miles. A well drilled in 2007 from an onshore location on Sakhalin Island to an offshore reservoir achieved a horizontal departure of seven miles." (Exxon Mobil, 2007).

Semisubmersible Floating Production Systems (FPS)

The first Floating Production Systems were converted semisubmersible MODUs, with permanent mooring systems installed and the drilling systems removed to free up variable load and deck space for production equipment. In many later conversions, particularly for service in Brazil, the drilling equipment was retained to provide either full drilling capability or completion and workover capability. Some newbuild units were also equipped for full drilling capability. It remained more common, however, for development wells to be drilled by MODUs and tied back to the FPS. One reason for this is that wells drilled from an FPS must be subsea wells. They must be drilled with the BOP stack on the seafloor, and they cannot be connected to the FPS directly by rigid risers. Rather, they must be completed using a subsea tree and tied back to the FPS with a flexible riser. These factors reduce the utility of drilling from an FPS and raise the costs.

The decision of whether to drill development wells from an FPS involves several considerations:

Safety issues, such as potential interference between the producing well risers and the drilling riser and the need for adequate separation of the drilling and production functions.

The areal extent of the reservoir(s) to be developed and the number of wells required. If the well targets are widely dispersed, it may be less expensive to use a MODU to drill vertical wells for subsea completion and tieback rather than drilling extended reach directional wells from the FPS. This is a decision that can only be made after careful analysis of the characteristics of the field in question, including the geology of the formations to be drilled.

The cost of equipping the FPS for drilling. This is not only a matter of the cost of the drilling rig itself. It also involves increases above the cost of the FPS equipped for production only. To support a drilling rig, an FPS will have to be larger and heavier, requiring greater hull displacement, than the same unit for production only, and it will need more installed power generation.

Beyond these factors, the configuration of drilling facilities aboard an FPS and the drilling methods and procedures differs little from those aboard a semisubmersible MODU.

FPSO

Despite the success of the drillship, conventional industry wisdom has always maintained that FPSOs were not suited to perform drilling operations. The ship-shape hull did not provide sufficient stability for drilling unless a turret mooring system was installed; and the size of the drilling turret reduced valuable storage capacity. Furthermore, even with a mooring turret, there would be a risk of interference between the drilling operations and the production risers, all of which would have to pass through the turret.

Nevertheless, the advantages of having drilling capability aboard an FPSO have attracted a number of solutions based on differing approaches to the problem. One concept involves the following key components:

A double-bowed hull that allows either end to be headed into the weather

A small turret mooring along with a DP system that can limit weathervaning to 90 degrees in either direction and lock the ship's heading during drilling operations

Production risers attached to the ship at one end of the hull. The ship would have to move over a well for drilling or workover, and the configuration of the flexible risers would allow them to move out of the way. The concept seems rather complex and subject to safety issues, although all the components are field-proven.

A second concept, designed for mild environments such as West Africa and Brazil, employs a multipoint conventional mooring system without weathervaning capability. At the center of the hull is a tension-leg section hard-moored to the seafloor and isolated from the vessel's heave motions. This section houses production trees for dry completions (a considerable advantage with some reservoirs). A drilling rig mounted on the main hull can operate through the moonpool in the tension-leg section to drill new wells or work over older wells. Again, the concept seems rather complex, and the tension-leg section within a ship's hull is unproven.

Perhaps the greatest advantage of drilling aboard an FPSO occurs when the production wells require frequent intervention, workover, or redrilling. For these situations, full drilling capability would not be needed and a lighter completion/workover rig could be used, as aboard the Jolliet TLP in the Gulf of Mexico. As of early 2007, however, no wells had been drilled from an operating FPSO, and the challenges of simultaneous production and drilling operations, with oil offloading added into the mix, remain daunting.

Several fifth generation drillships have been equipped to store significant volumes of oil and offload it to a tandem-moored barge or shuttle tanker. This capability is provided, however, to allow the drillship to conduct an extended well test rather than to support sustained production. And it does not involve simultaneous drilling and production.

Tension-leg platform (TLP)

The TLP was developed specifically to permit dry-tree surface completions aboard an FPU and to facilitate drilling ( Scale model of a TLP. Courtesy of Scale Reproductions, LLC. http://www.2scale.com). In effect, the TLP comes as close as possible to duplicating bottom-founded platform drilling aboard a floating platform. The first TLP was installed at the Hutton field in the UK Sector of the North Sea in 1984. Most subsequent TLPs have been installed in the deepwater Gulf of Mexico.

The tension-leg mooring virtually eliminates heave and roll motions and restricts horizontal excursion, so a TLP provides a very stable platform for drilling. The wells are drilled through a simple drilling template piled to the seafloor beneath the TLP. The biggest difference between a TLP and MODU, FPS or FPSO drilling involves the placement of the BOP stack. Since the TLP is so stable, the BOP can be placed at the surface aboard the FPU rather than on the seafloor. And since the wells are completed at the surface, there is no need for subsea trees.

A lesser difference involves the need for tensioning and motion compensation to accommodate the response to environmental loads. MODU's and conventionally moored FPSs and FPSOs require significant riser tensioning capacity and drillstring motion compensation capability to isolate these drilling components from vessel motions. While tensioning and motion compensation are still needed aboard a TLP, the overall requirements are greatly reduced.

Drilling from a TLP is thus in many respects much simpler than from a MODU, and the surface trees provide ready access for workover operations. Because variable load capacity is always limited on a TLP, however, the drilling system is highly optimized to eliminate unnecessary weight.

Spar platforms

Spar platforms offer the same kinds of advantages for drilling as TLPs. The basic design of a spar, a long, slender caisson structure that may extend 600 or 700 feet below the surface with ballast at the bottom and buoyancy near the top, delivers very favorable motions (. Scale model of a spar platform. Courtesy of Scale Reproductions, LLC. http://www.2scale.com. This allows spar wells to be drilled with the BOP at the surface and completed aboard the platform with surface trees. Tensioning and motion compensation requirements may be greater than with a TLP because a spar will exhibit some heave as well as roll and lateral excursion.

The great depth of the spar hull creates an issue with riser and drillstring guidance that does not occur with other FPUs or MODUs. The riser and drillstring must be guided at intervals along the length of the hull and at the hull bottom, or keel, where they exit the hull. This is similar to the drilling guides that are built into bottom-founded steel jacket platforms. The movements of a spar, however, put a lateral load on the riser and drillstring where they exit the bottom of the hull, creating a bend that can cause wear and fatigue. This must be monitored to reduce the risk of failure.

Spars offer one additional advantage that reduces drilling time: The main drilling riser does not have to be retrieved to the surface when drilling a series of production wells. Instead, it can remain deployed throughout the entire drilling program.

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FLOATING PRODUCTION UNITS According to French et. al (2006), approximately one-third of the active deepwater drilling rigs working in the Gulf of Mexico in 2005 were aboard Floating Production Units, although some of these rigs were engaged only in well completion and workover services rather than full drilling operations.

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Examples of the use of spar platform in increased water depths over the years.

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Examples of the use of spar platform in increased water depths over the years.

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World's deepest spar

Source: Devils-Tower.pdf

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SPAR: The robust, reliable deepwater solution

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Source: www.anadarko.com

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There are three types of spars, namely
- the original spar design,
- truss spars and
- cell spars.

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Source
https://www.rigzone.com/training/insight.asp?insight_id=307&c_id=12

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Source
https://www.rigzone.com/training/insight.asp?insight_id=307&c_id=12

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The spar consists of a large vertical cylinder bearing topsides with equipment. Similar to an iceberg, the majority of a spar facility is located beneath the water's surface, providing the facility increased stability.

Read more here - https://www.rigzone.com/training/insight.asp?insight_id=307&c_id=12

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Truss Spar is divided into three sections
- Hard Tank
- Middle Truss Section
- Soft Tank

Read more here - http://www.floatec.com/spar.htm

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Fort Worth Lumber Rafters Trusses Design