SUBSEA PRODUCTION SATISFIES TORDIS FIELD DEVELOPMENT

Brynjulv Klove, Erling Hestad
Saga Petroleum AS
Sandvika, Norway

Subsea production facilities will enable the satellite Tordis field in the Norwegian sector of the North Sea a degree of flexibility for development planning and also defer expenditures.

The facilities are designed to allow for simultaneous drilling, maintenance, and production operations.

The planned development, as presented in a July 1991 concept study report, consists of seven individual subsea wells connected to a subsea manifold. The manifold is tied back to Gullfaks C platform for processing of hydrocarbons, supplying water for injection, and controlling production (Fig. 1).

Start of production is scheduled for 1994. The Gullfaks operator has agreed to receive 12,000 cu m/day (75,500 b/d) of liquids for processing at Gullfaks.

FIELD DESCRIPTION

The Tordis field is in the southern part of Block 34/7 near the boundary between Blocks 34/7 and 34/10. The field is 9-12 km (5.6-7.5 miles) northwest of the Gullfaks installations and 12-18 km east of the Statfjord installations. The water depth across the field ranges from 140 m (459 ft) in the south to 230 m (755 ft) in the north (Fig. 2).

Block 34/7 was awarded as Production License 089 in 1984, with Saga Petroleum AS as the operator. Participating companies and their current interests in PL 089 are shown in Fig. 2.

The Tordis field was discovered in 1987 by Well 34/712, drilled in the western segment. After the second well, 34/7-14 was drilled in the autumn of 1989 in the southern segment, close to 90% of field's estimated recoverable hydrocarbons were proved. Only the eastern segment remains to be tested.

Both wells encountered oil in the Brent sandstones, the reservoir sandstones of the Tordis field. The reservoir is divided into an upper Brent and a lower Brent unit that are separated by the shale-sand-coal sequence of the Ness formation. Well testing has proven moderate to excellent productivities from the reservoir sandstones.

The aquifer size and degree of aquifer support are uncertain. Therefore, the capability for injecting water needs to be available in case the aquifer influx proves to be insufficient to sustain production.

A total of seven development wells are necessary to drain the field. Of these, five wells are planned to be producers. The other two wells are for water injection.

Because of the geometry of the structure, separate upper and lower Brent production wells are required. By injecting water into both zones from the same well, the required number of injection wells will be minimized.

In the eastern segment the production well will have a horizontal section (Fig. 2).

Production is planned to start in the third quarter of 1994 from two predrilled production wells in the southern and western segment. The other wells will be brought into production by consecutive drilling and completion.

Because of the expected aquifer support in the area, the water injection wells will be drilled and completed at the end of the drilling program.

The economically recoverable reserves are estimated to be 18 million cu m (113 million bbl). Production rates of individual wells are estimated to be between 2,000 and 4,000 cu m/day (12,600-25,200 b/d).

SUBSEA SYSTEM

Tordis will be developed by a subsea production system comprising of single satellite wells connected to a subsea manifold. The well stream will flow to Gullfaks C from which water will be supplied to the injection wells.

The Tordis subsea production system provides for five (plus two optional) production wells and two (plus one optional) water injection wells. The system is comprised of:

An integrated subsea manifold system for combined production and water injection service.
Satellite well systems and associated completion/ workover equipment
Subsea control and monitoring system
Flow lines and umbilicals, pull in and connection equipment
Remotely operated tool for component maintenance.

Subsea equipment, engineering, construction, and installation are based on field proven concepts and equipment.

Manifold and satellite wells are located in 200 m (656 ft) of water. All equipment is designed to be installed and maintained remotely without diver involvement. Conventional field-proven techniques and vessels are used for equipment handling and maintenance.

An anchored drilling rig will drill, complete, and workover wells. A guide wire-deployed choke pod running tool (CPRT) and a remotely operated vehicle (ROV) operated from a monohull vessel will perform individual component replacement and conventional intervention tasks.

A principal feature of the subsea development is the capability to undertake simultaneous drilling, maintenance, and production operations.

Satellite wells are spaced around the manifold but within the anchor spread and movement envelope of the drilling vessel (Fig. 3).

While working over an individual well, the risk of dropped objects on producing wells and the manifold has been minimized by spacing the wells apart and including dedicated dropped object/handling zones between wells. This arrangement also allows the monohull-vessel with the CPRT to access subsea equipment for component replacement tasks while the drilling rig is on location.

The principal components of the subsea system are illustrated in Fig. 4.

Material selection criteria are given in on the next page.

SYSTEM DESIGN

System design philosophies encompass factors related to:

Safety
Reliability
Field proven components
Diverless installation, operation, and maintenance
Operational flexibility towards reservoir uncertainty.

Safe and economic production of hydrocarbons was considered the highest priority and, therefore, the primary objective for the subsea production system. System design was governed by the requirement to minimize capital cost through the utilization of existing field-proven equipment and offshore installation techniques.

Operational flexibility with regard to reservoir drainage and deferring capital expenditure was also an important objective. The adoption of this philosophy implied that systems, equipment, and component designs, together with associated procedures for installation, operation, inspection, maintenance, and repair, be kept as simple as possible.

Furthermore, while not compromising overall system operation, manifold equipment configuration was to be evaluated such that only those items offering improved economic benefit to overall production, in terms of operational flexibility, were incorporated.

To allow for maximum system availability, a modular and component maintenance philosophy was adopted.

Where possible, equipment was to be designed to permit diverless retrieval to surface for repair/replacement using conventional drilling rig handling techniques for CPRT and ROV operated from a monohull vessel.

The principal functional, operational, and design requirements for the Tordis subsea system are shown in the box on the left.

MAINTENANCE

Maintenance of Tordis subsea equipment is based upon retrieving modules or individual components to the surface for repair or replacement.

Techniques and methods used to perform subsea intervention and equipment recovery will be by remote diverless systems using ROV/CPRT operated from a monohull vessel and riser/guide wire systems from a drilling rig.

Plans are to install and maintain the subsea equipment by remote means. Divers will only be used when remote systems fail or if it is considered safer or more cost effective to use divers in certain circumstances.

The diverless modular and component maintenance approach requires that equipment be specifically designed and configured into recoverable units that can be remotely installed and retrieved by tool systems assisted by vehicles. Tordis, in this respect, is representative and similar to many diverless production systems in the Norwegian sector.

Fig. 4 illustrates the Tordis subsea system modular and component maintenance approach.

Components considered critical in terms of production availability, and those that may require frequent repair or replacement, are designed to be individually recovered by CPRT from a monohull vessel. These components include the tree choke insert, tree control module, and manifold control module.

Larger and heavier modules, such as the trees, are handled with conventional drillstring/workover riser and guide wires from an anchored drilling rig.

During the field life, two types of intervention vessels will undertake routine maintenance. A monohull vessel with a dynamic positioning system will be used for deploying and operating the eyeball and work class ROV and CPRT.

For wire line and well workover tasks, a semisubmersible-type anchored drilling rig will be used.

Because of the satellite well arrangement, the subsea wire line operation can use a lubricator deployed from a monohull well-service vessel.

FLOW LINES

The flow lines and umbilical are to be installed within a single construction corridor by conventional lay barge and reel vessel with lines trenched for protection against fishing activities.

First-end connections for all lines will be at Gullfaks C. Second-end tie-ins at the manifold will use the deflect-to-connect method.

Two 10-in. steel production flow lines and one 10-in. steel water injection flow line link the manifold to Gullfaks C (GFC) platform. The manifold and GFC are approximately 12 km apart.

Thermal insulation for the production lines is achieved by applying an insulation layer to obtain a heat transfer coefficient of about 5.6 w/sq m-K.

A conventional installation vessel will lay the 10-in. lines. The methanol-injection line and the control umbilical will be laid simultaneously and form a strapped control bundle.

Flexible pipes will be used for the jumpers between the manifold and the satellite wells.

A first-end J-tube pull in will take place at the Gullfaks C platform. Flow line connection to the respective manifold headers will be achieved through a second-end horizontal deflect-to-connect pull in and connection operation performed by remote tooling.

Individual satellite wells are connected through separate flexible flow lines and umbilical jumpers which terminate in a horizontal first-end connection at the manifold and second-end pull in at the satellite well.

All horizontal connections are based on 11 in., 5,000 psi API hub-type profiles utilizing retrievable jackscrew clamp connectors. Horizontal receiver funnels for flow line and control umbilical tie-ins on the manifold and satellite wells are identical. This rationalization results in common pull in and connection tools and reduces cost.

The drilling rig will be anchored immediately after the manifold and flow line installation to perform pull in and connection tasks using the common tooling. Flexible jumper installation from the manifold to each satellite well is also done by the drilling rig. Alternatively, a reel lay vessel can be used if required.

SUBSEA MANIFOLD

The Tordis manifold (Fig. 5) has two primary elements:

Overtrawlable base structure with porches and horizontal receiver funnels for flow line and control umbilical horizontal connection.
Central piping area covered by overtrawlable and dropped object protection roof panels that contains necessary pipe work, valves, controls, trunking, and ROV retrievable components.

The manifold arrangement has these principal design features:

Satellite production and injection wells. These are arranged about a central piping area that provides CPRT/ROV access to manifold valves and control modules.
Two 10 in. production headers. The headers provide for round trip cleaning and inspection pigging operations. The headers are divided by an hydraulically operated pigging crossover valve which will also permit circulating out the contents of the 10-in. loop. The circulating fluid will be stabilized (nonhydratable) crude from Gullfaks C. The two headers allow for each to be operated at different pressures according to well requirements. Four wells are connected to one production header, the remaining three to the other.
A separate 10 in. water-injection header. This header, which can be pigged from the platform, supplies the three water injection wells. Cleaning pigs are exhausted onto the seabed and can be recovered with ROV assistance.
Controls for the trunking system.
Manifold control modules.
ROV-operated isolation valve for each satellite well.
ROV-operated flow line isolation valves for the 10 in. production flow lines.

Manifold branch pipe work between the respective production or water injection headers and satellite well tie-in arrangements incorporates ROV-operated 5 in. isolation valves. These valves are vertically oriented so that the valve stem is directly underneath the manifold protection roof. This permits access and operation by ROV tooling.

Production pipe work within the manifold will be insulated to a minimum overall heat transfer coefficient of 5.6 w/sq m-K. This is identical to the insulation selected for the production flow lines.

Manifold control trunking provides for interconnection of:

Electrohydraulic umbilical termination
Manifold control module
Umbilical termination to each satellite well
Chemical injection pipe work
Chemical injection module.

Dual chemical-injection points are provided on the production header for continuous injection of corrosion inhibitor.

Fixed mud mats and skirts on the underside of the base structure provide for seabed support and lateral load capacity against fishing gear snagging.

The seabed slope in the area may be 1-2. The requirement to level the manifold is not as critical as for the satellite wells.

The seabed installation site will be chosen to minimize leveling of equipment. Provision to level the structure can be made by hydro-leveling the skirted cell areas.

The air lifting weight of the complete manifold is estimated to be approximately 400 metric tons.

Removable roof panels provide for both overtrawlability and dropped object protection to key manifold equipment.

SATELLITE WELLS

Tordis development is based upon sequential drilling, completion, and tie-in of up to seven satellite production wells and three water injection wells (Fig. 6). This allows flexibility in field development planning and defers expenditure as much as possible.

To maximize the number of common components, equipment designs minimize variations between the production and injection trees. Both types of trees are of conventional design. Common features include:

Wire line well servicing either via conventional workover riser or by subsea wire line lubricator from a monohull.
5 x 2 in. completion system. Water injection wells feature 7-in. tubing below the downhole safety valve while the producers are completed with 5 1/2-in. tubing.
Integral forged valve block with hydraulically operated master, wing, and swab valves.

In addition, the master and swab valves can be operated by an ROV.

Hydraulically operated insert choke that can be retrieved by CPRT or by pulling the tree.
Well control module, retrievable by CPRT.
Horizontal pull in and connection arrangement for separate flow line jumper and control umbilical jumper tie-in.
Multiplex electrohydraulic control system.

DOWNHOLE EQUIPMENT

A 5 1/2 in. downhole completion is proposed for wells. The planned casing program includes:

30 in. surface conductor
18 3/4 in. surface casing
13 3/8 in. intermediate casing
10 3/4 in. production casing swaged down to 9 5/8 in. below the Scssv

A single tubing retrievable subsurface safety valve (Trsssv) will be installed. The valve is assumed to be shallow set and unbalanced. The required nominal operating pressure is 517 bar (7,500 psi).

Provisions have been made to monitor downhole temperature and pressure.

Well kill can be achieved either by bullheading or by circulating through a workover riser from a drilling rig.

Gravel packing of the production wells is expected to prevent sand production.

TREE ARRANGEMENT

The subsea satellite trees for either production or water injection service include a 5 1/8 in. production/injection bore and a 2 1/16 in. annulus bore. Both are rated to a design pressure of 345 bar (5,000 psi).

The tree design includes a master valve block, a reentry mandrel, a production or injection choke, a wellhead connector, a well control module, tree cap with connector, production or injection flow loops, choke module, flow line and umbilical inboard hubs, and the guide base.

Tubing displacement can be achieved with a workover riser and coiled tubing. Flushing of the infield flow line against the closed production master valve can be done by circulating from the drilling rig back to the production header in the manifold.

Annulus venting is provided through an annulus bleed line in the umbilical.

Chemical injection is planned for only the production trees. Chemical injection lines are routed directly from the chemical injection module on the manifold through the umbilical.

Downhole pressure and temperature monitoring is via a dedicated line to the satellite control module (SCM).

Electrical power/signal conductors to the downhole gauges are terminated at the SCM connection base.

The proposed production/injection choke is an hydraulically operated, insert retrievable, multiple orifice valve (MOV).

The choke design includes a fixed receptacle attached to the flanged outlet from the valve block, a collet connector for the insert, and an hydraulic actuator attached to the multiple valve disc spindle.

The collet is released and recovered on the surface, with the insert, by the CPRT.

PROTECTION STRUCTURE

The proposed tree protection structure is shown in Fig. 6. The protection is fabricated from steel and presents an overtrawlable profile. The structure foundation uses mud mats with skirts.

The skirts are fitted to provide full lateral resistance to snagging loads up to 50 metric tons.

There is minimum physical connection between the protection structure and satellite well drilling (temporary) guidebase. This arrangement permits installing the structure in advance or after commencing drilling operations. These operations can then be planned independently to optimize use of the drilling rig.

Furthermore, the structure easily allows for potential well thermal expansion during production.

The plan area of the structure will accommodate installing the elongated production guidebase (PGB) and subsequently the blow out preventor (BOP). Flow line and umbilical pull-in ramps are incorporated into the structure and provide for smooth engagement of the pull-in heads with the alignment funnels on the PGB.

Removal of the roof will permit vertical access to the tree and connection porch. Smaller removable panels within the main roof structure provide access for the CPRT to the satellite control module and choke module.

SUBSEA CONTROL

Control and monitoring of the manifold and satellite wells are performed by a multiplexed electrohydraulic control system (Figs. 5 and 6).

The operator enters commands via a keyboard terminal and, under normal process conditions, the operator maintains full control of the system. Subsea shutdowns will be controlled by the master control station (MCS) as input from the maintenance vessel emergency shutdown system, topside process shutdowns, or higher level shutdown inputs from the platform shutdown panel.

Subsea control modules operate in a slave mode to the MCS with one module assigned to each satellite tree and one module assigned to the manifold. All satellite control modules (SCM) are to be identical.

Satellite and manifold modules are not interchangeable. The satellite control module connection base is incorporated within the tree guide frame. All subsea control system hardware will be preinstalled on the manifold and trees with post installation maintenance carried out using the CPRT.

Redundancy within the subsea side of the system is confined to manifold distribution networks and supplies out to each satellite tree.

CONTROL SYSTEM

Valves and analog functions on each satellite tree will be monitored by a dedicated SCM. The manifold-mounted control module (MCM), in addition to controlling and monitoring the manifold header valves and some analog sensors, will control the distribution of hydraulic supplies to all satellite tree modules and housekeeping functions.

A single umbilical bundle carrying electrical and hydraulic power supplies, communication lines, and chemicals for corrosion and scale inhibition will run between the Gullfaks C platform and the subsea manifold.

An umbilical jumper will run from the manifold out to each satellite tree.

SUBSEA MODULES

The manifold-mounted control modules and satellite tree-mounted control modules can be recoverable using the CPRT. Failure of an SCM resulting in loss of tree valve control will require recovery and changing out the module. Loss of the MCM will not result in direct production shutdown or loss of hydraulic supply to satellite tree control modules.

Hydraulic supply failure to any control module will result in the module hydraulic subassembly failing to fail-safe mode (i.e., all actuated valves shall close). Electrical failure will result in loss of control and monitoring capability, but all actuated valves shall remain in their last commanded position.

The SCMs control all tree housekeeping functions, monitor all analog points, control hydraulic distribution throughout the subsea system, and also control chemical injection.

UMBILICALS

The 12 km long main umbilical will run between the platform and the manifold. The umbilical contains electrical and hydraulic power supplies, communication lines, and chemical-injection supply lines.

A 2 in. methanol steel line is strapped to the umbilical. The subsea end termination has an 11 in., API-type hub for hydraulic connections with the couplers for the electrical power and communication connections. These are available on the back of the termination head for connection.

Relatively short umbilical jumpers run between the manifold and each of the satellite trees. Typically, these are 75 m in length. Redundant power, signals, and hydraulic supply are incorporated with electrical signals superimposed onto the power cords.

Satellite umbilicals will have dual hydraulic supplies and dual power and communication lines. In addition, methanol for tree startup and shutdown purposes and scale inhibitor will be carried by the satellite umbilicals to the production satellite trees.

CHEMICAL INJECTION

Chemicals are to be injected into the well stream fluids at the production trees and the manifold to control hydrate formation, suppress scale build up, and reduce internal corrosion. All chemicals will be supplied from Gullfaks C platform.

Methanol injection will be controlled by hydraulically operated valves during production shut down and start up periods to suppress hydrate formation in the headers and flow lines.

A feed line, from the 2-in. line, supplies methanol to the chemical injection module for control and distribution to each production tree. Methanol will be injected principally to protect tree valves, chokes, and flexible jumpers from hydrates during shut down and start up periods.

Scale and deposit build up in production pipe work and flow lines will be suppressed by continuous injection of scale inhibitor after water breakthrough at each production tree.

Two dedicated lines in the main control umbilical supply corrosion inhibitor to the chemical injection module. Corrosion inhibitor will be injected into the two manifold production headers through separate lines. The chemical injection module can be retrieved for maintenance by the ROV.

CHOKE POD RUNNING TOOL

A simple guide wire-operated choke pod running tool deployed from a dynamically positioned (DP) monohull vessel or a rig, is used to retrieve manifold and tree components that include the manifold control modules, tree control module, and choke valve.

MARINE OPERATIONS

Development of the Tordis field will require the completion of the following installation activities

Manifold installation
Production and water injection flow line installations, including hookup, protection, and trenching
Dual lay installation of umbilical and methanol line, including hookup, protection, and trenching
Satellite well installation
Satellite well flexible jumper installation, including hookup and protection installation.

The above box shows the equipment installation sequence and the vessels' summary.

ACKNOWLEDGMENTS

The authors thank the PL 089 license group for the opportunity to present the Tordis field subsea design configuration. The definition of functional requirements and the corresponding design has been a joint effort from the Tordis project team within Saga Petroleum AS.

REFERENCES

"Tordis Field, Block 34/7 Plan for Development and Operation," December 1990.
"Tordis Concept Study Report," June 1991.
"Tordis Field Development Single Satellite Wells with Subsea Manifold Centre," SPE paper No. 23046, Offshore Europe 91, Aberdeen, September 1991.