Early tests of synthetic taut-leg moorings show promise
Conventional mooring limitations versus new taut-leg mooring capabilities. Synthetic mooring lines and suction anchoring play a vital role in taut-leg mooring. [39,390 bytes] Side profile of suction embedment plate anchor. [30,353 bytes] !-- AMC-developed suction embedment plate anchor (SEPLA) (patent pending) combines a suction follower (similar to a suction pile) to embed a plate anchor that is slotted vertically into the base of the follower. --
Operating and economic benefits for ultra-deepwater floaters
Peter G. S. Dove,Thomas M. Fulton
Filippo Librino,Colin R. Ocker
Aker Marine Contractors
- Conventional mooring limitations versus new taut-leg mooring capabilities. Synthetic mooring lines and suction anchoring play a vital role in taut-leg mooring. [39,390 bytes]
- Side profile of suction embedment plate anchor. [30,353 bytes] !--
- AMC-developed suction embedment plate anchor (SEPLA) (patent pending) combines a suction follower (similar to a suction pile) to embed a plate anchor that is slotted vertically into the base of the follower. --
Many ask the question: "Why it is necessary to consider moored vessels for ultra-deep water drilling and production operations at all?" Dynamic positioning (DP) technology has advanced rapidly in recent years, and the risks of mechanical failures and drive-offs have certainly been reduced.
Several large, sophisticated DP drilling vessels are currently planned, are being built or have recently entered service. These vessels are intended to fill at least part of the large demand for worldwide deep water drilling operations. To date, DP has been used primarily for exploratory drilling operations and, in some cases, long term well testing and early production.
DP has not been used for permanent facilities to date, and it is hard to see this happening at any time in the foreseeable future. Some operators suggest DP is possibly the only option for ultra-deep water drilling. Certainly, DP vessels will meet a major part of this demand. However, the authors firmly believe that moorings can meet the technical requirements for both drilling and production floaters in a safe and economic fashion and must be seriously considered for future ultra-deep water drilling and development programs.
Many operators and contractors are comfortable with mooring systems that use well-proven steel components. The problem is that steel components are depth limited for technical and practical reasons. The current depth limit is about 5,500 ft for existing MODUs, where all components are carried on board and deployed from the vessel in the field.
This limit can be increased to about 8,000 ft by using preset moorings with submersible buoys. However, the mooring components and installation operations are costly. One operator is building a 5th generation MODU intended to moor in water up to 8,000 ft with self-contained and deployed moorings. This unit will also include thruster assist. However, the practical water depth limit for mooring these units is governed largely by the ability to maintain acceptable watch circles in an operational or "drilling ahead" condition, as governed by the limitations of existing risers and bottom flex or ball joints.
TLMs using all steel components and submersible buoys improve watch circles and extend water depth limitations, but the systems become very difficult to deploy and costs increase exponentially with water depth. Synthetic rope will have to be adopted for TLMs to become cost effective in ultra-deepwater.
Preset rope systemsIn most cases, drilling contractors prefer self-contained on-vessel mooring components that can be deployed from the vessel at site. But TLMs using synthetic components, at least under the current understanding of technology, have to be preset (pre-installed). Drillers sometimes resist the preset approach because it is a departure from proven practice and allows them less control over mooring operations.
Preset moorings, however, have already been accepted and are routinely used by several operators and drilling contractors as the most cost effective means of mooring second and third generation MODUs in water depths with a range of 600-3,800 ft. Shell in the U.S. has committed to a preset moored MODU that uses a steel TLM including large submersible buoys and suction anchors for water depths up to 8,000 ft and will commence operations with this system later this year.
The operators and contractors using preset moorings have established that the benefits are threefold.
- Water depth limitations of the units can be substantially extended (from a mooring perspective)
- Rig productivity can be increased by minimizing downtime during setting up on site
- Smaller vessels can be used for mooring deployment.
Current TLM systemsTLMs must have anchors capable of withstanding vertical loads. Driven piles provide the only practical means to anchor moorings with vertical loading until recently. However, the current technology for driving piles, using underwater hammers, is limited to about a 4,000 ft water depth.
While this limit might be increased with a very costly development program, it is unlikely that a reasonable return on investment can be realized in the near future, and it is likely that industry will not support such development. Additionally, driven piles are not recoverable.
Suction embedment anchors, first developed by Shell in Europe in the late 1970s, have now been successfully used for mooring in several permanent applications for floaters. To date, there are about 150 suction embedment anchors installed worldwide. Late in 1996, at the request of Shell in the US, AMC developed design and installation procedures for a recoverable suction embedment anchor suitable for a MODU TLM application. Aker Gulf Marine fabricated the full scale test anchor, and AMC supervised a field test in about 3,200 ft of water.
The suction anchor was deployed off a large anchor handling vessel, lowered to the seafloor, and installed using an ROV-mounted pump skid package. The anchor was then load tested and recovered by reversing the pump operation on the skid package. Shell subsequently decided to use this technology to moor the MODU Marianas in up to 8,000 ft water depth. The steel moorings necessarily include large, expensive submersible buoys in each leg.
While suction embedment anchors work effectively, they are very large, costly, and relatively difficult to transport and handle. Shell's suction anchors were 12 ft in diameter, 65 ft long, weighed 85 tons, and are reported to cost about $250,000 each. Suction anchors for permanent facilities could weigh up to 150 tons and cost almost $500,000. While MODU suction anchors can be deployed and installed from AHVs (using several trips to and from a base port), larger permanent suction anchors may require the use of expensive construction vessels.
In 1990, AMC embarked on a joint industry study (JIP) to try and develop a new generation of fluke drag embedment anchors that could withstand vertical loads. This JIP, sponsored by seven oil companies and assisted by the two main anchor manufacturers (Bruce and Vryhof), included laboratory and field testing of various anchor types and resulted in the introduction to industry of the Stevmanta and Denla vertically loaded anchors (VLAs).
VLAs are drag embedded with a relatively shallow fluke angle. After reaching design depth, their full vertical load potential is achieved by adjusting the fluke angle (using a tripping mechanism). AMC's experience with both VLA types is that once installed correctly, they will withstand loads up to 200 times their own weight in any direction (including vertical loads). The problem is that VLAs are difficult to embed and require a drag force equal to about half their ultimate load capacity in order to initially embed to design depth. In addition, their final geographical location is difficult to predict.
Embedment anchorAlso, AMC recently developed a design for a new anchor called the Suction Embedment Plate Anchor (SEPLA), on which AMC has applied for a patent. The SEPLA combines two fully-developed anchoring concepts in a novel manner: a suction follower (similar to a suction pile) to embed a plate anchor that is slotted vertically into the base of the follower.
The combined follower and plate anchor are deployed similarly to a conventional suction anchor from an anchor handling or construction vessel. After being lowered to the seafloor, the follower and plate are allowed to self-penetrate. An ROV-mounted pump skid then is docked to the follower to evacuate water from the follower, thus allowing the plate anchor to reach its full design depth.
The means for maintaining the plate anchor in place are then immediately released and the follower is removed from the seafloor by reversing the pump and pulling up on the follower deployment line. This leaves the plate anchor in a vertical orientation. After a proof load is applied, it rotates to a position perpendicular to the load applied. At this final position, the plate anchor is able to develop its maximum holding capacity.
Plate anchors have been investigated and used by the US Navy for many years and are considered mature technology. A full design methodology, available in the public domain, was developed by the Naval Civil Engineering Laboratory (NCEL). Many of the US Navy's plate anchors are installed throughout the world to act as fleet moorings. The only problem with plate anchors to date has been the installation method.
The Navy has developed a number of methods, including a ballistics deployment system for small anchors and vibratory underwater hammers for larger anchors. The drag- embedded VLAs cited are simply another way to install a plate anchor.
Whether the anchor is a SEPLA, suction embedment, or drag embedment type, to a large extent, anchor capacity is dependent on the depth of burial and soil shear strength gradient, which also dictates anchor size. In the case of SEPLA or suction embedment anchors, the geographical position and depth of burial are know at the time of preset mooring installation. In the case of drag embedment anchors, these factors are not accurately known.
The only testing normally performed is winch stall-out during proof loading. If the anchor drags during this procedure, it must be rerun or piggy-backed. This will not be required with SEPLA or suction embedment anchors. Even if a problem is encountered, it can be dealt with off the critical path without the MODU on site.
Mooring case studyA case study was performed to compare operational and economic features of three mooring system types for a drilling operation in a 7,500 ft water depth. The MODU used for the comparison was Diamond Offshore's Ocean America. This unit was chosen because it represents the largest existing type of 4th generation rig.
The environmental loads on any new 5th generation rigs must be considered to be at least in this range. A detailed computer model of the rig was developed and motion analysis was performed using the program Mora. Environmental load calculations were performed using current industry accepted practices. The mooring analysis was performed using the quasi-static program G-Moor, and the program Mimosa was used for a dynamic analysis check.
The three mooring systems investigated were as follows:
- System 1: This was an 8-leg wire/chain catenary system using conventional fixed fluke, twin shank drag embedment anchors. The components are sized to suit the design loads. The mooring system is considered to be deployed with the rig on site with conventional means using two large anchor handling vessels (AHVs). The mooring system is considered to be part of the rig. The mooring system and thruster assist are reflected in the rig's day rate.
- System 2: This system incorporates two sets of 8-leg TLMs using all steel components, including wire/chain, submersible buoys, and suction embedment anchors. The components are sized to suit the design loads. One system is initially preset without the rig on site. The second system is then preset at the next location, and the MODU is moved from one system to the next in a "leap frog" fashion. Two AHVs (one large and one medium) are used to move the moorings and for rig hook-up and disconnection. The onboard rig wire sections are considered to be owned by the rig operator, as reflected in the rig's day rate. The remaining components are considered to be leased.
- System 3: This system incorporates two sets of 8-leg TLMs using wire, polyester and SEPLA anchors. The components are sized to suit the design loads. The two mooring system sets are handled and used in the same manner as System 2 above. Again, the onboard wire sections are considered to be owned by the rig operator with the remaining components leased.
Analysis design criteria
(1) 10-year return period hurricane: wind (one minute mean) - 72 knots; wave height (significant) - 39 ft; current (surface) - 2 knotsAs a result of the case study performed, the following criteria were examined:
(2) 10-year winter storm: wind (one minute mean) - 47 knots; wave height (significant) - 20 ft; current - 1.5 knots.
(3) 100-year winter storm (or sudden locally developing hurricane): wind (one minute mean) - 54 knots; wave height (significant) - 24 ft; current - 2 knots.
(4) 1-year loop current with associated environment: wind (one minute mean) - 47 knots; wave height (significant) - 16 ft; current at surface (with profile) - 2.5 knots. Drag loads imposed by the mooring lines were included in the analysis.
- Offsets in operating and survival conditions without any slacking or adjustment of moorings or use of thrusters: From results, the TLM system using polyester ropes (System 3) will achieve watch circles under 2% of water depth, even in a 100-year winter storm. In theory, drilling operations would be able to continue under these conditions. Even in a 10-year hurricane, the drilling riser would probably survive in the connected condition with System 3, which might be critical in a situation where a hurricane develops locally (similar to Hurricane Juan in 1985) and when there may not be time to disconnect the drilling riser. Offsets with the steel TLM (System 2) are slightly larger and some mooring adjustment would probably be necessary. With the conventional catenary system (System 1), it would definitely be necessary to use the onboard thrusters, in conjunction with mooring adjustments.
- Offsets in operating conditions with mooring adjustments only ? no use of system thrusters in System 1: System 1 requires considerable additional thruster use. Systems 2 and 3 would meet the requirement to maintain drilling, but it should be noted that System 3 is superior because it has an offset of only 1% of water depth in all conditions.
- Thruster requirements: In this evaluation, the estimated thruster requirements for Systems 1 and 2 are shown to meet the operating criteria for drilling (about 1% offset). In reality, the requirements will be less because of the ability to move the rig through an optimization of mooring line lengths, as determined through a mooring advisory program (MAP).
- Mooring footprints: This evaluation shows elevation views of the three mooring systems being evaluated and highlights the size of the footprints of the systems. System 3 requires considerably less real estate, which becomes increasingly important in deepwater and crowded field developments. Polyester TLM (System 3) offers many advantages over the other systems. While it is possible, in theory, to optimize the mooring systems further with mooring line length adjustments (or by using the thrusters in combination with mooring adjustments), in practice this is very difficult to accomplish and is dependent on the use of the MAP. There is only a minimal requirement to make any mooring line length adjustments with System 3 (except in the survival condition). In the event of a locally developing tropical storm or hurricane, when there is insufficient time to disconnect and pull the riser, System 3 is much less likely to invoke problems or loss of the riser.
Economic comparisonThe following assumptions were made in the economic comparison of the three mooring systems:
- Contract for MODU set at three (3) years
- Four wells drilled per year
- MODU for System 1 considered to be newbuild 5th generation type with drilling and stationkeeping capability (moorings and thrusters) up to 8,000 ft water depth
- MODU for Systems 2 and 3 is existing 4th generation type which includes upgrades to drill in 7,500 ft of water and has only 3,000 ft of 3 3/4-in. diameter wire rope for each leg stowed on rig
- MODU day rate spreads: System 1, inclusive of two large AHVs - $250k; Systems 2 and 3, inclusive of one large and one medium AHV - $215k.
From this comparison, it can be seen that System 1 is the most expensive. Over the three year contract, System 2 will save $17 million over System 1; System 3 will save about $23.5 million over System 1; and System 3 will also save about $6.5 million over System 2. Not taken in to account in the cost analysis is the amount of savings in rig productive drilling time seen by Systems 2 and 3 over System 1 (estimated to be 96 days). This time could allow the drilling of about two more wells in the three year period.
Projected progressBased on the results of the case study presented here, it is clear that polyester TLMs, especially using SEPLA anchors, could provide an attractive economic and operational alternative to DP for both exploratory and development drilling operations. If such a system can be proven in drilling operations, it is logical that the next steps can be taken to prove this new technology for production facilities.
In spite of the progress made by the Brazilians, it appears no other operators are currently prepared to take the step of using synthetic TLMs. Steps are, therefore, being taken by Aker Marine Contractors and other mooring industry leaders to move this technology toward worldwide acceptance.
Shell in the U.S. has reportedly used 2-in. diameter polyester lines as supply boat moorings for the Cognac project for about eight years. The mooring lines have been regularly inspected and have shown little deterioration in break tests after five years of service. The lines are still in use.
Working as part of the DeepStar project team in 1996, AMC designed and installed a single leg TLM for use as a 3,000 ft water depth standby mooring for supply vessels servicing the Auger TLP. The system incorporates several types of polyester rope construction about 3 1/2-in. in diameter and is maintained at about 50-60 kips tension.
The system has survived two hurricanes, and it has been exposed to considerable abuse due to service vessels regularly mooring to the upper buoy while standing by to berth at the platform, and it still remains intact. AMC plans to recover the system later in 1998 after two years of field service, at which time several rope samples will be subjected to break tests and compared with tests of new rope samples, as well as vigorous optical inspection and chemical fiber testing.
Also in 1996, Saga installed two legs using synthetic ropes (one leg with polyester and one with Dyneema) anchored with recoverable suction anchors on a MODU in about 4,200 ft of water in the North Sea. After two months of service, the legs were recovered. After testing, they were found to have break strengths close to design.
Several operators in Europe have undertaken vigorous laboratory testing to establish fatigue life, creep, and the presence of hysteresis. One phenomenon that was observed is that polyester rope, if subjected to a large number of cycles at tensions in excess of 50% of break strength, can demonstrate fairly large increases in stiffness. This has not, however, been confirmed in smaller scale tests in the US, and the method of measuring the stiffness is suspected of being in error.
In 1997, Petrobras conducted a test where large scale polyester ropes were laid down on the seafloor for a period of about three months. After the ropes were recovered, some deterioration in break strength was observed, reportedly because of abrasion on the fibers caused by the ingress of seabed sediment. Testing of a jacketing material to prevent this phenomenon is now being performed in Europe. No results have been released to date.
In late 1997, Statoil planned to install a barge in the North Sea moored with three polyester ropes approximately 7 in. in diameter. AMC (Norway) was selected as the installation contractor. In an unusually severe winter season, it was impossible to carry out the installation. It has been postponed until later in 1998.
In a joint venture with Marlow Ropes and a major operator, AMC is now close to finalizing plans for the installation of two 6-in. diameter polyester ropes as TLM substitutes for two of the wire/chain catenary moorings on a 4th generation MODU, planned to be moored in about 4,500 ft of water.
If testing of the new SEPLA anchor (set to begin in March 1998) proves successful, these polyester mooring lines will be anchored to the seafloor with recoverable SEPLA anchors. The plan is for the MODU to drill one or more wells with these test moorings. If the test is successful, the same operator may select a complete polyester SEPLA TLM for development drilling in over 6,000 ft of water scheduled to commence in early 1999.
Polyester TLMs using SEPLAs will offer significant operational and economic benefits over the other systems studied. Polyester TLMs with suction embedment anchors also offer significant operational benefits compared with steel systems.
The SEPLA, however, needs to be proven in full scale tests along with handling procedures for installing and recovering the polyester rope. Field experience in a drilling mode is definitely needed in the Gulf of Mexico in the immediate future. The authors firmly believe this experience will be achieved during 1998, allowing this new technology to become fact, not fiction.
Editor's Note: This is an abbreviated version of a paper entitled "Economic and Operational Benefits of Synthetic Taut Leg Moorings for Deepwater Floaters - Fact or Fiction," presented by the authors at the SNAME Texas Section meeting held in Houston in February. Full-length editions are available from the authors Aker Marine Contractors (Houston) or SNAME (New York).
Copyright 1998 Oil & Gas Journal. All Rights Reserved.