Paal Norheim
Norwegian Rig Consultants AS
Kristiansand, Norway
Environmental loads and large, heavy drilling risers impose design restrictions on drilling systems installed on deepwater tension leg platforms (TLPs).
The use of a full drilling package for deepwater TLPs requires detailed planning, especially in the early conceptual phase. An evaluation of a TLP prospect should include consideration of the following:
- The environmental conditions
- The size of the drilling riser needed
- The requirements for additional wells
- Possible redrilling during subsequent workovers.
A substantial cost of offshore developments comes from the drilling of the development wells. As the water depth increases, this cost constitutes a larger share of the total field development cost.
This is especially true for a TLP, mainly because of the requirement to establish connection with the subsea wellhead for each well and the special efforts needed because of TLP motions. Deepwater drilling from a TLP involves a number of time-consuming and costly operations as well as a large and complex drilling package on the platform. The drilling package occupies a large portion of the topside deck area and load capacity.
In some cases, the cost involved in full drilling operations from a deepwater TLP may be prohibitively high. For these situations, one way to make the prospect economically attractive is to predrill the wells from a floating vessel and use the TLP only as a wellhead platform. However, the use of a TLP only as a wellhead platform, with no drilling package onboard, introduces a number of disadvantages.
PREDRILLING WELLS
Predrilling development wells from a floating vessel, especially in deep water and harsh environments through a multiwell subsea template prepared for TLP tie back, will involve a certain element of risk. The handling of a long drilling riser with a large subsea blowout preventer (BOP) stack above a number of wells will require detailed safety and risk analysis. Because of the adjacent wellheads, the floating rig cannot pull off location as easily as in deepwater single weil drilling. Additionally, a substantial amount of time may be spent on standby operations and waiting on weather because of restrictions in latching of a subsea BOP stack to a wellhead located among other wells prepared for tie back. Drilling of highly deviated wells from a floating vessel may also be rather time consuming.
On some deepwater locations there will also be limitations for year round drilling by semisubmersibles, as well as limitations because of the few rigs capable of drilling in waters deeper than 1,000 m.
In a predrilling only scenario, the required number of wells will have to be set prior to the start of production because additional wells cannot be added after the TLP has been installed. This implies that the reservoir behavior should be well predicted prior to installation. For development of marginal fields, many operators tend to reduce the number of costly exploration wells and plan for flexibility in the number of platform wells.
Without a full drilling package onboard, there would have to be limited need for frequent and heavy well maintenance and workover operations.
One alternative is to use a semisubmersible as tender assistance to the TLP during the drilling period, The tender could accommodate all drilling supplies and utility facilities. However, there will be problems with keeping a semisubmersible a short but safe distance from the TLP, which will have irregular motions and considerable offset in deeper waters. Mooring lines for the floating rig may interfere with the TLP's tethers and risers.
DEEPWATER TLPS
Only one deepwater TLP has been installed to date--Conoco Inc.'s Jolliet TLP in 520 m of water in the Gulf of Mexico. This platform is a wellhead platform with no drilling package onboard. Jolliet has only a small workover rig, capable of limited well maintenance through the production riser. The only other TLP installed is the Conoco Hutton TLP in 150 m of water in the U.K. sector of the North Sea. Although this is not considered deep water, the Hutton TLP has a full drilling package, with some design features applicable for deeper waters.
Three other TLPs with full drilling packages are under planning or construction for installation in relatively deep waters in the near future.
Saga Petroleum's Snorre TLP is in the final construction phase and is scheduled for installation in August 1992 offshore Norway in 320 m of water. This TLP design will include a full drilling and workover package and will only have a limited number of wells predrilled (for early production and cash flow).
The drilling package consists of a separate drilling rig and substructure module and a pipe rack with mud and support systems integrated into the topside deck structure. The drilling rig is designed to cover all 50 well and export riser slots over a square area of 28 m x 60 m (Fig. 1). The fabrication of the Snorre drilling package for Saga Petroleum has been completed, and the drilling rig has been lifted onto the topside deck, prior to mating of the topside to the hull.
Conoco's Heidrun TLP is in the early, detailed engineering phase. Unlike other TLPS, this platform will have a hull made of concrete. Heidrun will be installed in 1995 offshore Norway in 350 m of water, and the proposal includes a permanent drilling package. The overall requirements for the Heidrun TLP are rather similar to those of the Snorre TLP.
Shell Oil Co.'s Auger TLP is under construction and will be installed in 872 m of water in the Gulf of Mexico in 1993. Although this platform will have a drilling package onboard, a subsea BOP stack with a low-pressure drilling riser will be used. This may be considered as a disadvantage in cost, compared to the surface systems on Hutton, Snorre, and Heidrun.
TLPs have also been considered for use on a number of other deepwater prospects, but no final decisions have been made yet. One of these is Chevron Corp.'s prospect in Green Canyon 205 in about 800 m of water,a decision is expected in early 1992. Chevron is planning for one or two drilling rigs on this TLP. Shell has considered a TLP as one of the development options for its Mars prospect in 950 m of water in the Gulf of Mexico.
Offshore Brazil, Petrobras is considering the use of a TLP for development of the Marlim/Albacora area of the Campos basin at a water depth of about 1,000 m. On this TLP the plans only call for a permanently installed workover rig.
DRILLING RISER
One feature of a TLP is the capability of having the Christmas trees and the drilling BOP located on the platform deck, similar to a conventional fixed platform. Drilling development wells with a surface BOP stack is advantageous from a safety perspective and is much less expensive than with a subsea BOP. A topside capable of handling a 200-250 ton subsea BOP stack will in most cases result in a rather complex and costly design for both the wellhead area and the drilling package.
The use of a surface BOP stack on a TLP implies that the stack will have to be located within the drilling substructure, mainly because this module can also transport the BOP from well slot to well slot. The surface BOP stack will be located on top of a high-pressure drilling riser which extends from the subsea wellhead through the platform wellhead area and up into the drilling substructure.
In spite of all risers kept in constant tension to minimize motion and stress, there will be a relative vertical motion between the riser top and the TLP deck structure. This motion can have a considerable impact on the design of the drilling facilities. With the BOP stack mounted on top of the drilling riser, the design has to allow for the entire stack, which may have a height of 5-7 m and a weight of 40-70 tons, to move up and down within the,. drilling structure.
The total height of the "BOP envelope" is determined by the up and down stroke observed during drilling on a particular well slot and by several other factors:
- Environmental loads
- Functional loads
- Installation tolerances
- Possible damage.
Up and down strokes of the riser result from TLP offset caused by environmental loads (waves, current, and wind on the hull and risers) in combination with riser dynamic behavior. With the platform in an offset position, the tethers pull the platform down into the water (Fig. 2).
The effects of the functional loads result from variations of the fluids (density, temperature, and pressure) within the riser. High temperatures from circulating drilling fluids will result in an up stroke effect. An up stroke effect will occur if the well is closed at the BOP and the drilling riser is exposed to any shut-in pressure.
Installation tolerances must be considered if a large multiwell template is used or if large variations in water depth exist. Accuracy of typical leveling sensors ranges around 0.5. Thus, some tolerances in riser space out must be included. The tolerances should anticipate inaccuracy in water depth measurements and variations in tide and storm surges.
Another factor considered in determining the BOP envelope is the riser damage condition if the tensioner system fails. Because of the loads involved in the riser tensioning system, it is difficult to design a system that can instantly compensate for a loss of tensioner stiffness and avoid having the riser top/BOP fall downward if a failure occurs. Some regulations therefore require an allowance of a 25% loss of riser tensioning in TLP design.
It is not sufficient to design for an up and down stroke from a fixed neutral position or riser datum. The neutral position may vary, especially with a multiwell template and large variations in environmental and operating conditions.
RISER DESIGN
The vertical motion of the BOP stack will require a number of special design features (Fig. 3). Above the stack there will have to be a low-pressure slip joint to compensate for the relative motion between the stack and drill floor. Because of the sealing requirements in the slip joint, the riser will have to be properly centralized above and below the BOP.
These centralizers can only guide special riser joints (without buoyancy elements, etc.) and can therefore not be activated during riser installation or retrieval.
To avoid damage from a swinging riser, a "soft centralizing" device must be used during such operations. The BOP handling equipment has to be able to install and remove the BOP in various elevations.
The design of the drilling substructure for the Snorre TLP allows for a vertical movement of about 3.0 m with a 16 3/4-in., 5,000-psi BOP stack (40 tons). Including the stack, the total height of the BOP envelope is approximately 7.5 m.
Riser analysis work has not been completed for the Heidrun TLP. Tentative figures indicate that the stack will have to be able to move about 2.5 m up and down within the module. The planned BOP is a 21 1/4-in., 5,000-psi stack (70 tons). The total height of this BOP envelope will be about 10 m.
The dynamic behavior of the risers requires sufficient spacing between them to avoid collision and possible vortex shedding effects from riser congestion. Considering also the motions of the Christmas trees and the production jumper hose areas, the typical spacing between the well slots on the platform will be near 4-5 m.
The drilling rig and substructure will cover a large area on the topside of a multiwell platform. Consequently, there will be a large span between the main skid beams for the drilling rig. For the Snorre and Heidrun TLPs, this span be about 25-28 m, resulting in transverse skid beams of about 4 m in height. This adds considerable weight to the platform.
To limit riser motion and stress caused by the TLP horizontal displacement and the direct wave loading on the riser, all risers must be maintained under a near-constant top tension. The tension must be sized so that riser interference is avoided for all installed risers in all operating and enviro=ental conditions.
High-pressure drilling risers have considerably larger diameters than production risers. Thus, the drilling substructure and supporting structures below will be exposed to relatively large tensioner loads. This is especially a factor with a large diameter drilling riser in deep water where the buoyancy elements cannot compensate for the hydrostatic head on the riser.
For the Snorre TLP the maximum expected tension load from the 22-in. drilling riser is estimated at about 450 tons. The tentative figure for the Heidrun TLP is about 950 tons with a 26-in. drilling riser.
HORIZONTAL ACCELERATION
Because of irregular, sideways motions of a TLP, there will be a certain horizontal acceleration of the topside facilities. On the Snorre and Heidrun TLPS, the designed horizontal accelerations are approximately 0.18 and 0.12 G, respectively.
Tubular handling and structural design are the main areas influenced by the horizontal acceleration.
As a result of the horizontal acceleration, especially when combined with rough environmental conditions, the platform pedestal cranes will frequently be shut down. Certain critical drilling operations can last several days, such as installation of the drilling riser or running casing. Systems must be available for tubular handling operations independent of the cranes.
The requirement for crane assistance should be limited to transport of tubulars from supply boat to pipe rack and for handling of certain special riser components from pipe rack to drill floor. The long production riser taper joint, heavy drilling riser flex joints, and Christmas trees can be transported to the drilling rig prior to the start of critical operations. These items, handled best by the cranes because of their sizes and configurations, will therefore be available even if the cranes are temporarily shut down.
Safety aspects of TLP crane operations contribute to the design of special tubular-handling facilities. During crane operations, heavy loads (such as a 15-ton drilling riser joint) can swing unpredictably as a result of the TLP motions. Such hazardous situations can damage riser buoyancy elements, external control lines, or anticorrosion coatings.
The tubular-handling system built for the Snorre TLP (with a similar system tentatively planned for the Heidrun TLP) consists of a gantry crane and a purpose-built pipe shuttle machine. The gantry cranes transfer tubulars, equipment, and containers from and around the pipe rack area. The gantry cranes load tubulars onto a pipe shuttle arrangement which transfers the tubulars to and from the drill floor. (For a multiwell platform like Snorre, the distance between the pipe rack and the drill floor is about 24 m horizontally and 10 m vertically, if the drilling rig is skidded to the extreme well positions.) The pipe shuttle system consists of two wagons which can carry a number of various size tubulars safely to the drill floor V-door area.
On most standard rigs, platform cranes transport the tubulars to the drill floor V-door area. A drill floor winch typically picks up the tubulars there and transports them to the drill floor (either to the mouse hole or to the well center).
The Snorre and Heidrun TLPs have been designed with a slot in the drill floor which allows delivery of the tubulars directly to the well center by the pipe shuttle system. The derrick top drive pipe handler then picks up the tubulars. This system eliminates the risk of swinging loads at the drill floor.
TLP horizontal acceleration also affects the structural design of the modules and drilling derrick. An open slot in the drill floor/V-door area provides several operational and safety advantages. For most TLP concepts, such as for Snorre and Heidrun, a perimeter girder (structural beam) cannot be included in the drill floor/V-door area. This structural beam normally forms an important element in the structural truss configuration which handles the large operating loads on the drilling derrick and substructure.
A unique steel configuration had to be designed to avoid excessive amounts of structural steel in the drilling substructure. The main steel framework of the drilling substructure and mud module must reflect the horizontal inertia loads induced by the TLP motions. A higher number of diagonals bracing the decks have to be included in the design.
The drilling derrick design requires additional consideration to avoid fatigue problems caused by TLP dynamics.
TUBULAR STORAGE
A full drilling package requires storage of a considerable number of riser joints, special subsea components, drill pipe, and casing. Alternatively, the riser joints could be stored on a supply boat and transported between the rig and the vessel via the platform cranes. In this situation the rig becomes totally dependent upon the platform cranes; this dependence should be avoided because of the critical nature of riser installation operations.
At an absolute minimum, tubular storage should accommodate a complete riser system during installation or retrieval. This will help avoid a situation in which one riser hangs between others already in place.
Under a more standard approach, a well should be completed after it is drilled. The well is then prepared for production while the rig is released for use on the next well. Thus, the pipe storage facilities will need to accommodate the complete drilling riser, one production riser, one string of production tubing, and the drill pipe simultaneously.
In harsh environment locations like offshore Norway, most operators require drilling operations capable of continuous operations for at least 7 days without the need for supplies. This means that the last casing string or the surface casing for the next well will have to be added to the scenario above.
Storage of all these tubulars, in addition to a number of special components like riser workover assemblies, production riser taper joints, production riser tensioner units, and flex joints, will put a relatively high operational load on and occupy a large area of the topside.
With a 26-in., high-pressure drilling riser, a 9 5/8-in. production riser, a 5 1/2-in. production tubing string, and a drillstring stored simultaneously, the total storage weight requirement will increase from about 1,000 to 3,000 tons when the water depth increases from 300 to 1,500 m. In this scenario, the 26-in., high-pressure drilling riser constitutes the highest storage load. A typical 26-in., high-pressure drilling riser joint of 15 m with buoyancy elements and collars will weigh approximately 15 tons.
A 22-in. riser could be used to reduce the load. However, on a typical North Sea well, the 22-in. riser would have to be pulled before the 20-in. casing is run. This is a time-consuming and costly operation, especially as the water gets deeper.
Most drilling risers are made of steel, which adds significantly to the load. One method of reducing the weight and complexity of the drilling package is to use titanium as material for the drilling riser. The lighter materials could reduce the riser tension load requirements and the riser storage load on the topside. Because titanium has a lower stiffness than steel, the large, complex riser tensioning system could be replaced by hard tie-offs for some applications. Although titanium risers would reduce the load, the storage space requirements would not change.
INSTALLATION TIME
Another element in the design of a full drilling package is the actual installation time required for a high-pressure drilling riser. The design must consider the consequences if the installation operation must halt when the riser is hanging in the water between a number of production risers. As the water gets deeper, the time involved for running and pulling of the drilling riser becomes so long that the environmental conditions on some locations may change considerably during the operations.
For the Snorre TLP, it is estimated that running and intermediate pressure testing of the 22-in. drilling riser under ideal conditions will last about 35-40 hr. On the Heidrun TLP, the preliminary estimates for the 26-in. riser indicate running and testing operations will take about 45-50 hr.
Thus, the installation time for a high-pressure drilling riser in 600-800 m may take as long as 3-4 days. The critical installation period related to the weather window, defined as the time from deployment of the subsea wellhead connector until final latching of the connector onto the subsea wellhead housing, will last about 2 days in 600-800 m. This is about the same amount of time required for recovery of the complete drilling riser in case the riser cannot be latched to the subsea wellhead for some reason.
On a multiwell platform a relatively high frequency of drilling riser installation and retrieval operations may occur.
If the drilling riser is sized to allow for all casing running operations, the riser will only have to be installed once per well. The disadvantage is that the diameter of the riser will be large, with subsequent high tensioning load requirements and a large area required for storage and handling.
CUTTINGS DISPOSAL
On most locations, water-based drill cuttings can be discharged off the side of the platform. Unlike a bottom-supported fixed platform, TLPs have a subsea wellhead template (or alternatively single wellheads) below the platform. Covering the subsea facilities with drilled cuttings should be avoided because of the cost and difficulties with cleaning operations by remotely operated vehicles and the risk of damaging the subsea wellhead system.
For some deepwater locations, the under-water current may limit the amount of drilled cuttings that can reach the template. Nevertheless, most operators would be reluctant to dump cuttings directly below the platform. The cuttings should not be dumped such that they can contaminate the seawater at the platform seawater intake. Also, some regulatory agencies prefer that operators not spread cuttings over a large area of the seabed around the platform.
Fig. 4 illustrates the cuttings disposal system designed for the Snorre TLP. From the various positions of the drilling rig, the cuttings will be flushed by seawater through fixed piping to one of the TLP hull columns.
The cuttings enter a subsea dump line which carries them to a deposit location approximately 200 m away from the template. The disposal end of the hose remains about 40 m above the seabed, held by a submerged buoy anchored to a bottom foundation. This will help avoid plugging of the line and will keep the line away from the template. The hose can move in a horizontal plane according to the TLP offset position.
To avoid excessive wear to the hose in the splash zone, the hose will enter into a scabbard and a specially designed shoulder at the bottom of the column. Total cost of the cuttings dump line system ranges around $200,000, excluding installation.
For TLPS, the problem with disposal of drill cuttings contaminated with oilbased mud is not much different than that faced by bottom-supported platforms. The exception is that TLPs have a limited load for storage of oily cuttings. Bottom-supported structures normally have a higher capacity to take increased deck loads with only a nominal increase in cost.
For the Snorre TLP, where the use of oil-based mud is considered as a backup only, the systems are arranged so that oily cuttings can be transported on a conveyor belt out of the drilling substructure and into Storage containers for further storage and transport to shore,
Other oily cuttings disposal methods under evaluation include grinding and injection down a drilled well.
WEIGHT AND COST
The total weight of a full drilling package for a multiwell deepwater TLP will typically range around 4,000-6,000 tons, depending upon the topside concept and the site conditions.
For a skidable drilling rig for typical North Sea conditions and drilling programs, the dry weight will approach 2,000-3,000 tons. The addition of operational and variable loads increases the total operating weight to 4,000-6,000 tons, for which the TLP ballasting system will have to compensate with the rig in various positions.
The weight of the mud and drilling supply facilities will vary between 2,000 and 4,000 tons. The lower figure represents a typical integrated topside concept, and the upper figure represents a separate module. Total operating weight of such a module will approach 8,000 tons, including pipe rack loads.
A full drilling package for a multiwell deepwater TLP will typically cost about 0.8-1.4 billion NOK ($110-200 million). This figure includes all engineering, procurement, and construction related to the drilling package.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.