HORIZONTAL SUBSEA TREES ALLOW FREQUENT DEEPWATER WORKOVERS

Mike Krenek
FMC Wellhead Equipment Division
Houston
Gene Hall
Amoco Corp.
Shekou, China
Wang Zhu Sheng
China Offshore Nanhai East Corp.
Shekou, China

Horizontal subsea wellheads have found application in the Liuhua oil field in the South China Sea. These trees allow installation and retrieval of downhole equipment through the tree without having to disturb the tree or its external connections to flow lines, service lines, or control umbilicals.

This access to the well is important because the Liuhua wells will be produced with electrical submersible pumps (ESPs), which may have relatively short intervals between maintenance, leading to frequent well work. The wells will be completed subsea in about 300 m of water.

The large bore, horizontal trees allow all downhole equipment to be pulled without removal of the subsea tree. This wellhead configuration also provides well control and vertical access to downhole equipment through a conventional marine drilling riser and subsea blowout preventer (BOP), eliminating the need for costly specialized completion risers.

Another benefit of the horizontal tree is its extremely compact profile with a low number of valves for well control. Valve size and spacing are decoupled from the size and bore spacing of the tubing hanger.

The tree's low profile geometry reduces costs of manufacturing the tree and framework and optimizes load transfer to the wellhead.

LIUHUA

Amoco Orient Petroleum Co., China Offshore Oil Nanhai East Corp., and Kerr McGee Liuhua Ltd. are jointly developing the Liuhua field, the largest offshore oil deposit in the South China Sea. The Liuhua 11-1 field is in 300 m of water about 200 km southeast of Hong Kong (map, p. 60). The field is in a severe weather environment, where typhoons occur frequently and can complicate operations.

The Liuhua field was discovered in 1987 and is estimated to contain more than 1 billion bbl of oil. Despite the significant size of the field, the complex reservoir characteristics and environmental conditions make economic development of Liuhua a major challenge. Well test and model data indicated the reservoir would produce heavy oil under active water drive with high initial production followed by a rapid decline as water production increases.

Because of the water depth and low-energy producing characteristics of the reservoir, a conventional multiplatform development was dismissed because of unattractive economics.

Furthermore, the harsh weather environment puts exceptional technical constraints on floating production systems.

The project design for Liuhua includes two permanently moored floating production vessels and a subsea production system.

The subsea production system consists of all necessary equipment to transfer the oil from the reservoir to the floating production, storage, and offloading (FPSO) vessel, a converted 141,000-dwt crude tanker.

The floating production system is scheduled for installation in 1995 with initial subsea work beginning in mid-1995. Drilling and completion activity will continue until 1997. The FPSO is scheduled for installation in early 1996. The subsea production manifold and 6 of the 21 ESP horizontal subsea trees were recently shipped to begin commercial development of the Liuhua III oil field (Fig. 1).

SURFACE EQUIPMENT

The floating production system is a converted semisubmersible drilling vessel. The vessel will retain its ability to drill, complete, and workover wells while providing support for the subsea production and well systems.

The floating production system will have sufficient electric power generation capacity for the ESPS. The vessel will be permanently moored, and all power and control cables will be tethered from the surface.

The FPSO will be located in 293 m of water approximately 3 km from the floating production system via an internal turret mooring system. The 10-leg inverted catenary mooring system is designed to withstand 100-year typhoon conditions.

Production will flow through the subsea system and pipeline to the FPSO, which will have the capacity to process 65,000 bo/d from a total maximum fluid capacity of 300,000 b/d. The FPSO will also be capable of storing 720,000 bbl of processed crude. The crude will be offloaded via a tandem mooring system to shuttle tankers.

SUBSEA MANIFOLD

The subsea systems are among the most innovative components of the Liuhua development. The manifold system uses a modular concept, which is a unique design for the offshore industry. This system consists of several relatively small components that can be assembled on site by a conventional floating rig and crew, eliminating the need for a costly prebuilt template and its installation.

Moreover, the floating production system is equipped with five moon pools and allows simultaneous operations during the initial seafloor installations and well completion activities.

The concept includes hard pipe jumpers between the wells and a compact central manifold. All the subsea equipment can be installed or retrieved using the floating production system, which will improve the economics of the project. There will be two remotely operated subsea vehicles for all. underwater intervention activities. Safety and other control systems will be operated with hydraulic control systems on the floating production system.

Fig. 2 shows the hydraulic distribution base on the subsea manifold.

HORIZONTAL SUBSEA TREES

The Liuhua development will have about 20 wells, all of which will be produced through horizontal subsea trees with ESPS.

This project is the oil industry's first use of ESPs in a multiwell subsea environment.

The horizontal trees are designed to facilitate the many well operations anticipated during the life of the field. Each tree will have a state-of-the-art electrical connector to supply power to the ESPs. The downhole completions were designed to be simple, yet functional.

The horizontal subsea trees are a flexible, economical alternative to conventional completions. The horizontal subsea tree diverts the flow of well bore fluids horizontally through the tree body.

Unlike conventional subsea trees, the system provides well control and vertical access through a standard marine riser and subsea BOP. This feature eliminates the need for expensive completion and workover risers and allows retrieval of the downhole ESPs and the completion without having to retrieve the tree.

The key benefits of this horizontal subsea tree configuration include the following:

Permits frequent tripping of the ESP and tubing workovers without removal of the tree or flow lines
Eliminates the need for complex dual riser systems and associated tools
Streamlines the workover control system and reduces workover umbilical size
Reduces total number of valves required (valve size is independent of tubing string size)
Greatly simplifies tooling package and installation procedures (reduces troubleshooting downtime).

Horizontal trees use the same field-proven components found in conventional subsea trees (tubing heads, subsea valves, tubing hangers, and wellhead connectors), but the components are modified and reconfigured to suit the special operating conditions for frequent full bore workover access through the tree.

In the early part of the installation sequence, the horizontal tree is similar to a conventional tree with a tubing head. Because the tubing hanger lands in the body of the tree, a horizontal tree has the advantages of a tubing head spool used in conventional subsea completions. A horizontal tree is generally insensitive to the position of casing hangers and packoffs in the wellhead below. It provides a known machined landing shoulder for precise interface between the tubing hanger and the tree.

The horizontal tree also) provides new seal profiles to land, lock, and seal the tubing hanger.

Fig. 3 is a schematic of a horizontal subsea tubing hanger system for ESP applications.

Because the horizontal tree is installed early in the installation operation, it can be accessed using the marine riser and subsea BOP to land the tubing hanger, thus eliminating the need for a completion riser (and its rig up time).

Both conventional and horizontal trees require approximately the same number of steps and running tool equipment for wire line operations. The horizontal tree, however, allows full-bore access for downhole tools.

The wellhead is installed first, followed by the tree, tubing hanger, and tree cap. The novel order of installation eliminates a significant amount of intervention steps and equipment during workovers and reduces some equipment and run times required for installation. Table I compares the installation sequences for conventional and horizontal trees. Tables 2 and 3 compare the subsea hardware wire line and downhole workover procedures, respectively, for conventional and horizontal trees.

SEALS

Because the subsea trees will be used in an ESP application, they will be configured as an elastomeric sealing system with a separate sealing wear sleeve in the tree bore. Elastomeric seals are the primary seals on the tubing hanger, wire line plug, and internal tree cap.

The sleeve permits retrieval of the seal surfaces in the event of damage from frequent tripping of the pumps through the tree bore. This system also eliminates retrieval of the tree which would be necessary if no wear sleeve were present.

Without the replaceable sleeve, it would be necessary to retrieve the tree to repair the tubing hanger seal surface, if damaged.

The barrier philosophy used for the ESP completion is different from that for a natural lift completion. One of the barriers is considered to be switching the pumps off.

The master valves are bolted on, dual barriers are used upstream of the master valve, and a crown plug is installed through the tubing hanger running tool (THRT), prior to retrieval of the THRT and blowout preventer (BOP).

The second pressure barrier is an external tree cap (installed after retrieval of the subsea BOP), used also to establish the electrical connection to the ESP pump.

Several production mode barrier options were considered for the Liuhua project (Fig. 4). Option 2 was selected but was modified to have an external guide ring to transmit the bending load from the in-water power cable to the tree housing.

Because the electrical connector is a large-diameter, pin-type connector, the production bore of the tubing hanger must be moved off the centerline of the well, and the system effectively becomes a parallel bore system.

Thus, an hydraulically operated tubing hanger running and retrieval tool must be used in conjunction with an orientation system.

The external tree cap also provides the same transfer of workover to production controls provided on conventional completions. A universal running tool will be used to transfer the tree cap from the tree to a stump, allowing access to the well (Fig. 5).

This procedure eliminates the need for retrieving the in-water power cable during workovers.