NEW TECHNOLOGY IMPROVES TLP WELLHEAD FIND TREE DESIGN

Noel Monjure, Frank Adamek
ABB Vetco Gray Inc.
Houston

Identifying the operational requirements specific to tension leg platforms (TLPS) helps determine the optimum wellhead and production tree design.

Because of the special operating conditions and compliant nature of TLPS, the surface wellhead components and completion equipment have design requirements that differ from those on fixed platforms. Designers must consider space restrictions, weight limitations, riser motion and tensioning, alignment, equipment performance, and cost in designing wellheads for use on TLPS.

TLPs are still considered a developing technology and, therefore, no unique standards can be established yet for surface wellheads or production tree equipment. Until standards are determined by accepted industry practice; each project will likely include different configurations of surface components and design concepts.

The guidelines in this article can help engineers establish a functional specification for surface wellhead and production tree design for a typical TLP project.

The basic performance (pressure and flow containment) of all surface control equipment must be weighed against modified designs that accommodate restrictions caused by riser movement, tensioner positioning, weight and work space limitations, and surface alignment.

For long-term TLP operations, the following should be considered in the design of surface wellhead equipment:

• Metal-to-metal seals at all wet surfaces and for all environmental seals

• Proven pipe suspension and tensioning techniques

• New generation, nonflanged wellhead connectors (The connectors should have capacities published following the American Petroleum Institute Bulletin 6AF format; they should be preloaded to greater than the combined external loads, incorporate static metal-to-metal seals, and be economic and safe.)

• Preloaded flow line connectors

• Easy access for service and maintenance.

SURFACE WELLHEADS

The performance requirements of surface drilling or completion equipment are ultimately related to the characteristics of the reservoirs drilled. These downhole conditions determine the pressures and thermal stresses that must be accommodated. Additionally, they influence the casing and tubing string size and material.

After the basic well parameters are defined, the engineer can determine the initial specifications for the surface wellhead, production tree valves, and subsea wellhead equipment. One of the best references for establishing the initial requirements is API Specification 6A, "Specification for Surface Wellhead and Christmas Tree Equipment."1 This document is the industry standard for determining acceptable design and performance criteria for basic service conditions.

The following information is of prime importance in selecting subsea wellhead equipment and determining the requirements for the casing strings to be tied back to surface: well bore and casing sizes; lengths, weights, and grades of pipe; materials used during each phase of drilling or production; necessary performance level of each wellhead component during drilling and production, and the quality assurance level (product specification) recommended.

API Specification 17D, "Specification for Subsea Wellhead and Christmas Tree Equipment," establishes the minimum requirements for subsea drilling and completion equipment, similar to those established for surface equipment, and is the preferred industry guideline for subsea equipment.:

After the basic well bore conditions (pressure and produced fluid composition) are established, the operator then determines which casing strings will be tied back to surface. Generally, an increase in the number of casing strings above the mud line usually increases the tension requirements, the weight, and cost of the TLP. Production pressure and fluid composition, however, may require redundant protective barriers (additional casing strings). The number of casing strings brought back to surface is also a function of company policy and regulatory requirements.

After the basic requirements for production and completion are established, additional specifications for the surface equipment can be reviewed. Conventional surface wellhead and production tree assemblies can support and seal the tubulars and contain the production at the surface (Fig. 1). The use of standard products, instead of custom products, permits a larger supply of components and spare parts.

Conventional wellhead assemblies, however, do not generally address the special considerations of compliant TLP structures. Based on the final design and completion programs, these considerations could include fire-resistant sealing technology, adjustable orientation or vertically oriented wellheads, nonwelded attachment systems to accommodate production during drilling operations, reduced weight and height of the entire assembly, restricted operating space, adjustable hangers and seals for the casing strings, and extraordinary requirements for resistance to torsion and bending at the connections.

FIRE RESISTANCE

The threat of surface fires has primarily been addressed by the use of emergency shutdown systems, surface-controlled downhole safety valves, and deluge systems to control flames. Because of several recent large fires, many offshore projects are being designed with technology to resist failure during a fire.

The fire-resistant equipment primarily features special designs developed in 1981 to meet the requirements of API RP 6F, or the SIPM requirements as they are commonly known. API has updated its requirements for qualification of fire-resistant equipments.3-5 These specifications outline testing procedures and acceptance criteria for fire-resistant valves and end connections.

Although the decision to include fire-resistant technology is usually a matter of individual company policy, equipment selected for TLP applications should be certified by documented test results according to published industry standards.6 This decision should be made after the production conditions are known because the different levels of fire-resistant technology can significantly affect the total size and weight of the assembly. Fig. 2 is a schematic of a typical TLP wellhead with both API and SIPM levels of fire-resistant technology,

FLEXIBLE ORIENTATION

The operator should have the flexibility to install the surface wellhead components onto the production riser from the subsea wellhead and align them in relation to the TLP well deck and production facilities with as few limits as possible. The simplest method of accomplishing unlimited orientation is to weld the surface wellhead directly to the top of the riser joint using the conventional socket weld or butt weld method.

This method is suitable for TLPs that do not require any simultaneous production and drilling operations, that do not have a critical initial elevation with respect to the well deck, or that have a wellhead that may be attached before riser joint installation. Another option is to install the initial surface well component using a nonwelded casing attachment system that provides both a rigid connection and sufficient seals.

Flanged connections should be avoided between the wellhead and blowout preventer (BOP). Although standard flanged connections are mechanically satisfactory for drilling and completions on a TLP, they are too limited in terms of orientation. A socket-welded connection, butt-welded hub, and a nonwelded casing attachment system are nonflanged well connectors that require no alignment (Fig. 3).

Systems requiring annular casing valve outlets may require predetermined outlet orientation.

ADJUSTABLE HEIGHT

TLPs are typically designed to support the maximum deck load with a minimum weight of structural materials to save cost. Because of overall size optimization, spacing between topside deck levels is kept to a minimum defined by total height dimensions required for a BOP assembly or other handling equipment.

The surface assembly will have some height limitations in the static condition and may have vertical displacement limitations in the dynamic condition.

If vertical displacement of the surface equipment is restricted by the deck spacing, the initial elevation of the wellhead equipment becomes critical. Several methods provide adjustable vertical placement. The simplest method is to cut off the riser joint after it has been run and then to weld the surface wellhead in the proper position. Other methods include field-machined profiles with unlimited adjustment and adjustable sleeve designs with variable adjustment within predetermined limits (Fig. 4).

The final selection of a particular design depends on the sealing requirements between the wellhead and the riser joint, the amount of adjustment required, and the mechanical capacity required of the connection between the riser joint and the surface wellhead.

NONWELDED ATTACHMENT

Nonwelded methods of attaching wellheads to tubulars are being studied again because of the need to have surface wellhead systems that are compatible with production-while-drilling operations.

Nonwelded attachment systems are particularly well suited for TLPs that require provisions for having additional wells drilled after the TLP is installed or that have predrilled wells that will require tie back after production begins.

Nonwelded attachment methods are divided into two broad categories:

• A mechanical means of gripping the casing on its outside

• An extrusion method that deforms the casino, internally.

Both methods are updated versions of technology introduced in the 1940s and 1950S.

The suitability of a particular method depends primarily on the strength and diameter of the riser joint or casing and the type of seals required.

For ambient-temperature, low-pressure oil service, traditional oil field elastomer seals may be sufficient. For more severe service conditions and especially for gas service, metal seals or impermeable nonmetal seals should be used.7-8

API PR 2 test programs have confirmed the greater reliability of metal-to-metal seals compared to elastomer seals involved in thermal and pressure cycling associated with offshore production.

These systems should be evaluated according to industry standards to ensure performance consistent with the other components in the surface wellhead system.

Nonwelded attachment is also possible using a thread on, hub-style connector using field-machining techniques. This method can be time consuming, however.

WEIGHT REDUCTION

Some weight reduction is possible through modification of the surface wellhead systems. The principal method of weight reduction is to eliminate as many connections as possible in the wellhead and production tree. Consolidation of the components into as few sections as possible also eliminates potential leak paths.

Each operator must balance the weight reductions against the restricted operational characteristics of totally consolidated wellheads and trees, however. If a tieback program consists of 9-5/8-in. x 7-in. x 3-1/2-in. diameters, a composite wellhead would attach to the 9-5/8-in. casing (or riser) and feature internal profiles for the 7-in. casing and 3-1/2-in. tubing. Any problems with the 7 in. or smaller profile could be difficult during remedial work.

Similarly, although composite block production trees reduce both height and weight without extraordinary measures, the operator should balance projected maintenance and replacemerit against the potential weight savings. If the total weight of the surface assembly is extremely critical, the components may even be shaped (trimmed) to eliminate unnecessary material.

HEIGHT REDUCTION

In general, the overall height of the surface wellhead and tree assembly may be restricted. Reducing the height helps reduce the weight.

Height restrictions on the assemblies are only effective when the initial elevation of the equipment is controlled within the specified tolerances or taken into consideration by the tensioning design or other design particulars. The possible use of accessory equipment in the well deck area sometimes requires a greater vertical clearance than the surface equipment requires. Thus, there may be no height restriction on the wellhead and tree.

Fig. 5 compares the height of a standard 9-5/8-in. x 7-in. x 3-1/16-in. 10M conventional wellhead to that of modified wellhead for use on a TLP.

The use of horizontal tree technology can substantially reduce well bay height. Basically, the traditional tubing head and hanger assembly are converted to a flow spool, allowing the produced fluids to exit the wellhead at right angles to the vertical tubing. This design puts the surface tree into a horizontal configuration.

Additional safety measures are used in this design to provide multiple barriers to the well pressure during workovers. Several metal sealing plugs are normally positioned above the tubing hanger to ensure that safe intervention methods can be used to nipple up the BOP and access the well bore.

This design may save additional costs throughout the life of the wells. As reservoir pressure decreases, the wells may need to be put on electrical submersible pump. Electrical submersible pumps and tubing strings are routinely pulled for repair or replacement. Using horizontal trees allows the tubing string and downhole pump to be pulled without dismantling the entire tree or flow line.

QUICK CONNECTORS

Conventional API flanges have been used as reliable wellhead connectors onshore and offshore. The higher costs of deepwater drilling and the greater emphasis on system safety have forced equipment suppliers to reexamine the cost effectiveness and operating safety of API flanges.

Several new quick-makeup wellhead connectors can significantly reduce the time required for installation or disassemble, of BOPs or wellhead components. The use of quick connectors reduces overall costs and increases personnel, property, and environmental safety by minimizing the time a well is left open.

In addition, the hazards of using hammer wrenches on large diameter studs are eliminated. Newer connectors are purposely designed to rely on wedgeing principles to generate connection preloads at much lower operating torques.10-12 The removal of loose parts, such as studs, nuts, or clamp segments, improves safety by eliminating the possibility that these components could be dropped.

RESTRICTED SPACE

The wellhead components must be designed to operate in the smallest possible space on TLPs. The TLP weight reduction programs reduce and limit well bay geometry.

Altering the equipment orientation at the surface overcomes some of these limitations. The trees can be rotated or the traditional row and column system of positioning can be modified. The designers must consider the effect of remedial operations and maintenance, such as removal of valve actuators and installation of valve removal lubricators on annular outlets.

CASING HANGERS

The TLPs installed to date have typically used one or more strings of casing or production riser joints to connect or tie back the subsea wellhead to the surface wellhead equipment.

The outer string (9-5/8 in., for example) may be attached to the subsea well system using a modified subsea wellhead connector. This riser is extended back to the surface and either suspended in a tensioning member or tensioned directly.

For a low-pressure completion, a single casing string and the tubing string may be a sufficient barrier. For high pressures or dangerous fluids, an additional barrier may be necessary. In this case, the riser becomes an intermediate tie-back string and the next inner barrier is the production casing string.

If the production casing is run during a predrilling program and is suspended in the subsea wellhead, a casing riser is run from the surface and tied back to the subsea casing hanger. The casing is suspended, sealed, and locked in place in the surface wellhead using two principal methods that also provide for tensioning of the production casing riser.

These two methods are the slip-type casino hanger and the adjustable mandrel casing hanger which is threaded directly onto the casing riser. Typical casing slips feature a hardened tooth design that bites in only one direction and can increase casing tension simply with an upward pull. Most designs split apart and wrap around the casing. The seals, which may be self contained or separately installed in the slip assembly, are either weight energized or mechanically activated.

Special designs can strip over the casing and eliminate separation of the BOP during installation. This operation usually suffers from the drawback that the casing riser must still be cut off and removed before operations continue.

Adjustable mandrel casing hangers are threaded directly into the casing string at a predetermined casing connection and run through the BOP. After the downhole operations are completed, the casing is tensioned and a locking mechanism is engaged at the surface to maintain the tension. Preloading the casing mechanism at the surface is a key element in preventing failures because of fatigue from the cyclical movement of a TLP.

For applications where the production casing is run and suspended completely from the surface equipment, threaded mandrel casing hangers provide sufficient load bearing capacity to support entire production casing strings and provide desired pretensioning capabilities at the surface. If the casing should become stuck before the adjustable mandrel hanger is in position, however, a backup system is necessary to meet both loadcarrying and pretensioning requirements.

A new cutter allows precision internal separation of the casing through the BOP. This hollow-bore, spindle casing cutter is run inside the stuck casing. An hydraulically powered rotating cutting head cuts the casing cleanly and prepares it for installation of a slip-type casing hanger.

After the slip assembly is installed and the casing pretensioned, the annulus can be sealed with either elastomer or metal seals. Redundant, preloaded metal-to-metal seals can be used with either the adjustable mandrel casing hanger or the slip-type casing hanger."

ADJUSTABLE TIE-BACK SUB

Tie-back operations under BOP control preclude the use of sliptype adjustable hangers and require a casing length adjustment. This adjustment ensures that tension is always maintained in the casing between the subsea tie back and the surface hanger.

Adjusting the casing length is required because the distance from the subsea well and the surface wellhead is not known. This distance differs from well to well, and there are variations in the threaded connection length at casing joint makeup.

THERE ARE THREE BASIC WAYS TO PROVIDE THIS ADJUSTMENT:

• A movable load ring is incorporated on the casing hanger. This ring is usually threaded and turned or tensioned until it seats on the load shoulder of the wellhead high-pressure housing. This method requires additional wellhead housing height to accommodate the hanger positioning.

• The entire wellhead may have to be moved relative to the low-pressure housing (casing). The movement of the wellhead provides for closures of the gap between the next smaller size casing hanger load shoulder and the high-pressure housing load shoulder. Thus, each wellhead is adjusted and is a different height relative to the wellhead floor. This method also affects the vertical space required on the TLP.

• An adjustment sub within the casing string is used to change the effective length of the string. The length of the casing is adjusted by various means so that the casing hanger rests (or is preloaded) on the high-pressure housing load shoulder. The adjustment-type sub used successfully in the field can be cate-orized as threaded (requiring a certain amount of rotation) or a straight-pull type using a running tool or casing spear. Whatever the tensioning method used, a reliable seal mechanism is required between the adjustable sub's parts under relative motion. A metal-to-metal seal with an elastomer backup is preferable.

TORSION AND BENDING

The dynamic nature of TLPs requires flexible flow lines and annular monitor lines to connect the surface wellhead and production tree to the facilities on the production deck. This relative movement between the platform and the production tree induces bending loads on the rigid connectors attaching the flow line to the wing sections of the tree, on the wellhead connections, and on any connections in the tree. The movement may result in torsional loading whenever the flow lines or annular lines become asymmetrical to the center lines of the surface wellhead and tree. Similar bending or torsion loads may be applied during workovers when the BOP is installed.

The bending and torsion loads are based on many variables related to the general design of the TLP and are beyond the scope of this article. Once these forces have been determined, end connectors must be selected (consult API Bulletin 6AF, "Bulletin on Capabilities of API Flanges Under Combined Loads").15

This API document provides information on the performance of standard API flanges under combinations of pressure, tension, and bending loads. Torsional load resistance can be found from the number, size and yield strength of the bolting used in each connection after other stresses have been applied.

Some proprietary end connections can provide greater resistance to applied external loads and can provide other characteristics useful for TLP applications.

The characteristics of proprietary end connections should be known and published in a format similar to API Bulletin 6AF.

The potential cyclic nature of the expansions, contractions, and external loadings should also be addressed with properly preloaded connections.

Connectors preloaded to resist all rated external combined rated working pressure (at a minimum) or test pressure (optimum) offer the greatest resistance to fatigue damage. Connectors that are not preloaded, or sufficiently preloaded, are not only more fatigue prone but also promote relative movement between the assembly components.

This movement causes the seal element to fret (wear away), resulting in premature joint/seal failure under normal operating conditions. Minimally preloaded connections should be avoided in TLP applications. Fig. 6 shows the typical forces on a surface wellhead and production tree.

REFERENCES

1. American Petroleum Institute Specification 6A, "Specification for Surface Wellhead and Christmas Tree Equipment," 16th edition.

2. API Specification 17D, "Specification for Subsea Wellhead and Christmas Tree Equipment," 1st edition.

3. API Specification 6FA, "Specification for Fire Tests of Valves."

4. API Specification 6FD, "Specification for Fire Tests of End Connectors."

5. API Specification 6FC, "Specification for Fire Tests of Valves with Selective Backseats."

6. Adamek, F., Bond, R., and Cimpos, A., "Fire Test of a 13-3/8" 5M NT-2 Connector to the Requirements of API 6FB (Part II), April 1, 1992, for Offshore Well Bay Conditions," ABB Vetco Gray International Report, HTS-920680, Rev. 1, April 1992.

7. Hunter, R.C., and Johnson, R J., "Gas Transmission Through a Plastically Deformed Metallic Interface," American Society of Mechanical Engineers Energy Sources Technology Conference and Exhibition, paper No. 89-PET-4, January 1989.

8. Galle, G.J., Johnson, R.I., and Adamek, R.J., "Titanium Dynamic Metal Seal for 30,000 psi Gas Service," ASME Offshore Mechanics and Arctic Engineering Engineering Conference, Calgary, June 1992.

9. Adamek, F., and Bond, R., " Performance Verification Testing (PR 2) of a 13 5/8" 15M NT-2 Connector with a Size 137 Grayloc Metal Seal to the Requirements of API 6A, Appendix F, 16th edition, for Temperature Class K Through 75-350 F.)," ABB Vetco Gray Report, HTS-920703, June 1992.

10. Adamek, F.C., and Humphrey, B., "Offshore Drilling and Production Time Saving Quick Connect and Disconnect Wellhead Connectors," paper No. 6776, Offshore Technology Conference, Houston, May 1991.

11. Yu, A., Sweeney, C., and Stephen, G., "The Application of FEA in a High Pressure Quick Disconnect Optimization," ASME Energy Sources Technology Conference and Exhibition, paper No. 91-PET29, January 1991.

12. Fowler, J.H., and Writt, R.J., "Application of API 6A and 16A Stress Criteria to a Large Diameter Connector," ASME Energy Sources Technology Conference and Exhibition, paper No. 90-PET17, January 1990.

13. Monjure, N., "Application of New Surface Wellhead Technology for improved Safety and Performance," American Association of Drilling Engineers meeting, Lafayette, La., September 1992.

14. Milberger, L -J., and Boehm, C.F., "High-Performance Metal-Seal System for Subsea Wellhead Equipment," paper No. 6083, Offshore Technology Conference, Houston, May 1989.

15. API Bulletin 6AF, "Bulletin on Capabilities of API Flanges Under Combined Loads," Ist edition.