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MODU riser and mooring systems

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For successful floating mobile offshore drilling unit (MODU) operations, proper marine riser and mooring equipment and their management are critical. When dealing with MODU operations, there are two types of stationkeeping systems, spread mooring and DP.

MODU mooring equipment

The vast majority of floating MODUs are equipped with spread-mooring systems. Some have a limited amount of dynamic thruster assist to their spread-mooring system. Almost all of today’s semi and drillship MODUs have an eight-point mooring system consisting of anchor chain, wire rope, or a combination. Most of the deeper-water units have a combination of anchor chain on the anchor end and wire rope on the rig end. For a very few ultradeepwater operations, synthetic mooring line is used to increase the strength-to-weight ratio of the mooring line. However, the synthetic mooring line is not carried or deployed by the MODU, which is a distinct disadvantage from an operations standpoint.

The anchor chain used on most MODUs ranges between 2¾ in. and 3½ in., with the predominant sizes being 3 in. and 3¼ in. Anchor chain comes in various grades, the most common being oilrig quality (ORQ), followed by R3S (20% stronger than ORQ) and RQ4 (30% stronger than ORQ).

Wire ropes range from 2¾-in. to 3¾-in. outside diameter (OD) and may be as long as 15,000 ft, although the average is closer to 6,000 to 9,000 ft per line. The rated break strength of wire rope varies widely, depending on the construction and manufacturer. For example, API EIPS grade 3 in. is rated at 389-tonnes breaking strength, but Bridon Dyformed DB2K 3 in. is rated at 530 tonnes, or 36% more strength.

For combination mooring systems, it is important to match the strength ratings of the wire rope and chain. Quality assurance is a critical issue for mooring lines and related equipment.

Mooring System Performance Optimal Water Depths
Anchor chain Generally performs better in shallow water depths because most of the strength is used for restoring force rather than holding up the chain’s weight < 600 ft
Wire rope Best for deep water because the strength-to-weight ratio is higher and more important in deeper water >1,000 ft
Combination wire-rope/chain systems Best for deep water because the strength-to-weight ratio is higher and more important in deeper water > 2,000 ft

Spread-moored MODUs, depending on the metocean, can generally moor in up to ≈ 5,000 ft; however, in benign to mild metocean conditions, some MODUs can meet industry standards to moor in up to 8,000 ft. Increasingly used in ultradeepwater depths is the “taut mooring line” system, which uses synthetic mooring line and spring buoys and is prelaid, as shown in Fig. 1.

Taut mooring line system details:

  • The current world record for this type of mooring system was set by the Deepwater Nautilus (Fig. 2) in the GOM at 8,950 ft in 2004.
  • This type of system is prelaid by anchor handling boats ahead of the arrival of the MODU.
  • The taut-line systems are expensive and time-consuming to handle; however, they extend the mooring capability of some MODUs to deeper water depths and may be very economical compared with a Dynamic Positioning (DP) unit, especially for very long wells and development projects.

Anchors with very high holding power have been developed that range in dead weight from 7,500 to more than 15,000 tons. The larger anchors perform best when the mooring line reaches the ocean bottom on or near tangent at full design tension; however, new vertical-load anchors have proved to be successful for special cases.

Vertical-load Anchor Benefits Vertical-load Anchor Drawbacks
  • Work well with some types of taut-line systems
  • Are difficult to set
  • Take special equipment
  • Cannot be carried by the MODU

Deck machinery to store, deploy, and retrieve the anchors and mooring lines for a deepwater mooring system can be massive, expensive, and heavy. Fig. 3 shows a typical layout on one corner of a semi MODU for a deepwater combination chain/wire-rope mooring system. Chain is stored in chain lockers in the columns below the deck machinery. The chain and wire rope are connected and disconnected for storage at a platform below the deck machinery level. This operation usually takes from 20 to 40 minutes for the latter operation.

Subsea equipment

Fig. 4 shows all the components and their location for subsea equipment, usually defined as anything under the rotary of a floating MODU down to the ocean floor. The subsea blowout preventer (BOP) stack consists of:

  • The lower package - mostly BOPs
  • The upper package - lower marine-riser package

The BOP stack is in two parts such that, in an emergency, the marine riser can be disconnected from the lower BOP at the lower marine-riser package:

The BOP stack
  • Used primarily for well control
  • The BOP stack usually consists of a minimum of four ram-type and two annular-type BOPs with three to four sets of double-outlet failsafe close valves
  • Valves are in sets of two with an inner and outer valve, all failsafe, with the choke side having a minimum of two sets and the kill side having one or two sets.
  • The choke-and-kill pipeline runs are routed up past the flex joint and to the surface by use of lines attached to the marine riser. During well-control operations, the well is circulated down the drillpipe, up the choke line, and through a choke manifold in a controlled manner to pressure balance or “kill” the well.
The marine riser
  • Used primarily to guide objects in and out of the wellbore:
  • Bits
  • Logging tools
  • Casing
  • Wellhead hangers
  • Seal assemblies
  • Serves as a return conduit for drilling fluids and cuttings
  • Carries auxiliary lines on the outside of the main conduit for the following:
  • The kill: pump down to the well
  • Choke: flow a kick back to the rig
  • Mud-circulating line: help lift drill cuttings up the large-internal-diameter riser tube
  • Hydraulic conduit: hydraulic power fluid for activating the BOP stack
The flex joint at the top of the BOP stack is a pivot point to reduce stresses in the riser and acts as a hinge point. The slip or telescopic joint allows vertical motion between the floating MODU and BOP stack and marine riser, which are attached to the ocean bottom.

The outer barrel of the slip joint, attached to the BOP stack, is tensioned with strung wire rope by 6 to 16 pneumatic tensioners ranging in capacity from 80,000 to 250,000 lbf each. Riser tensioners are usually pneumatic rod/cylinder assemblies with wire rope attached to the outer barrel (the part attached to the seabed) of the slip joint. Total installed riser tension pull varies with water depth rating for the MODU, but a very-shallow-water unit will have ≈ 640,000-lbf tension and the newer MODUs will have ≈ 1.6 to 2.0 million lbf.

A new type of riser-tension system consisting of large, very long hydraulic cylinders (referred to as inline tensioners) attached to the slip joint and substructure has recently been installed on some of the newer floating MODUs with tension capabilities of up to 4.8 million lbf. Total stroke for all riser tensioners usually is 50 ft, but some of the deeper-water units must have more stroke length in case the MODU moves off the well without disconnecting the lower marine-riser package from the BOP stack.

Atop the inner barrel of the slip joint, which is attached to the rig’s substructure, is the diverter assembly. The diverter assembly is used to divert fluids, usually gas, that the marine riser may have in it. The diverter assembly has a low-pressure (500-psi WP) packer that may close around the drillstring and divert fluid horizontally by use of diverter lines. Diverter lines (12- to 16-in. outer diameter) are used to route well fluid away from the rig and overboard in the unlikely event that unwanted fluids should come to the surface. More detailed information is given about subsea equipment in Ref. 1.[1]

Motion compensation

To maintain constant weight on bit for a floating MODU, drillstring motion compensation (DSC) is required. Thus, the industry has developed inline and crown-block motion-compensation equipment:

  • Inline: travels with the traveling block
  • Crown-block: is located on top of the derrick and part of the crown assembly

Most drillstring motion compensators are inline and passive (the drillstring motion compensators react to MODU motion rather than sensing it, as does an active system). Drillstring motion compensator’s stroke is usually 15 to 25 ft, with an average of 18 ft; however, most floating units will not operate the drillstring motion compensators with more than 10 to 12 ft of heave. Active systems usually involve the drawworks motors that dissipate the energy though the rig’s power-plant generators. This is one reason why DP drillships with a large power-plant system use active heave-compensation systems.

The BOP control system is critical and is probably the most difficult in which to maintain the high degree of reliability required for safe offshore operations. Most floating MODUs use all hydraulic systems by use of pilot valves in a “pod” on the subsea BOP stack (Fig. 4) shifted by pilot lines from the surface. The power fluid is usually sent down a hydraulic conduit on the marine riser. Some deeper-water units (> 5,000 ft) use a multiplex electrically coded system as the signal medium for shifting the pilot valves in the pods. Industry standards require subsea rams to close in 45 seconds and the annulars in 60 seconds; thus, signal time is critical and very time dependent. Subsea BOP stacks differ from land BOP stacks in that they:

  • Stay assembled
  • Have remote stabbing capabilities
  • Have hydraulic wellhead and riser connectors
  • Have mechanical riser connectors
  • Have BOPs and valves that are hydraulically actuated
  • Have guidance systems
  • Are controlled remotely per the above description

The key to successful floating MODU operations is managing the marine-riser and mooring system together and in harmony. As stated, the mooring system objective is to restore the floating MODU within specified limits over the wellbore through varying degrees of environmental conditions and rig operations. Hole position or vessel offset from the wellbore is usually monitored with acoustic hole position indicators that work in percentage of water depth from the wellbore. Riser angle at the flex joint located on the Lower Marine Riser Package (LMRP) is also measured acoustically. Table 1 is an example set of criteria for allowable differential riser angle (difference between the BOP and riser angle at the flex joint, not with vertical) and hole position, depending on the rig operation being conducted. The primary purposes of these guidelines are to achieve riser angles so that tools can be run/pulled through the BOP stack and flex joint without hanging up or creating damage, to prevent damage to the subsea equipment because of drillstring key seating, and to ensure adequate structural integrity of the marine-riser system.

Surface BOP

Recently, a new form of floating drilling has been developed in which the BOPs are located in the cellar deck rather than on the ocean bottom. With standard floating drilling, it is anticipated that the subsea BOPs can secure the well if the MODU:

  • Has a mooring failure
  • Loses its station over the wellbore because of environmental conditions
  • Experiences a riser failure or any other mishap

With the surface BOP approach (Fig. 5), the loss of hole position by the MODU or a failed riser means that the well will probably be lost. The concept is that seawater head will kill the well in the event of a riser failure because:

  • The riser is high pressure (usually 13⅜- or 16-in. casing)
  • The metocean is very benign
  • The well pressure is normal gradient

It has been very economically successful in the Far East, and has cut well costs by as much as 70%; however, the risk of losing the well and/or having a blowout has deterred many operators from using the approach. One mitigating approach is to put a complete shutoff device at the ocean floor (usually at least one shear ram with hydraulic connectors top and bottom). This approach increases the expense and time to the point of losing all savings. However, in ultra deepwater, the well is circulated up small-ID kill and choke lines, causing significant backpressure on the formation, while the surface BOP with the large high-pressure casing and BOPs at the surface eliminates the problem. In other words, there are pros and cons for every approach.[2]

Slim risers

Another approach similar to surface BOP is the “slim riser” approach (Fig. 6). The standard subsea system is built around an 18¾-in.-ID BOP stack and wellhead system that ordinarily uses a 21-in.-OD riser. The standard system has the capability to run up to nine casing strings by means of hangers and liners under certain conditions. In deep water where the margins between formation fracture gradient and hydrostatic head of the drilling mud to maintain well control is very close, many casing strings are often required. The GOM has this requirement, often resulting in very expensive wells costing U.S. $50 million and sometimes more than $100 million.

If a more standard deepwater well is to be drilled with only two to three casing strings through the BOP stack, a 16-in.-OD riser may be used. This results in far lower mud volume requirements because of a smaller drilled hole and smaller riser ID, which in turn requires less marine-riser tension, less deck space, and thus less variable deck load (VDL). Most importantly, these reduced quantities allow a third- or fourth-generation MODU to be used at reduced day rate rather than a fifth-generation unit.[3] A capable third or fourth generation semi rated for 5,000 ft water depth can be increased to 7,500 ft or over.

Well control in deep water is much more difficult than off a jackup MODU or a land rig. Detection and proper circulation is delicate and takes training, concentration, and patience, due to factors such as:

  • The smaller margin of safety between the fracture gradient and mud hydrostatic pressure being
  • The shut-in point (subsea BOP) being much closer to the influx formation
  • The detection point still at the rotary
  • Long runs of kill and choke lines on the marine risers having small IDs
  • Usually minimum of 3 in., with most being 3½ to 5 in

To date, the industry has an excellent deepwater well-control record


  1. McCrae, H. 2003. Marine Riser Systems and Subsea Blowout Preventers, first edition, Unit 5, Lesson 10. Austin, Texas: University of Texas at Austin.
  2. Childers, M. 2005. Surface BOP, Slim Rise or Conventional 21-Inch Riser - What is the Best Concept to Use. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 23-25 February. SPE-92762-MS.
  3. Childers, M. and Quintero, A. 2004. Slim Riser - A Cost-Effective Tool for Ultra Deepwater Drilling. Presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, Malaysia, 13-15 September. SPE-87982-MS.

See also

MODU selection

MODU types


Noteworthy papers in OnePetro

External links