The use of subsea completions tied back to existing platforms has allowed the development of marginal fields in the U.K. sector of the North Sea (Fig. 1).
Contractual agreements between various operators permit production from the Staffa field and the Lyell field to flow to the Ninian Southern platform. The lower capital expenditure provided an economic incentive to develop these small fields.
The Alwyn field in the North Sea will continue its development through the Alwyn North Extension project with a three-well cluster of subsea completions. With drilling and completion operations "batched" on the three wells, the operator has cut the development risk, difficulty, and cost.
These topics, other subsea developments, and subsea production equipment were covered in papers presented at the eighth Subsea 91 International Conference, held in London Dec. 4 3, 1991.
LYELL HELD
Advances in subsea technology and the availability of spare capacity at the nearby Ninian Southern platform, operated by Chevron U.K. Ltd., have allowed the economic development of Conoco (U.K.) Ltd.'s Lyell field in the North Sea.
The Lyell field, located about 60 miles east of the Shetlands, contains approximately 400 million bbl, but a base case scenario required economic runs at 30 million bbl to ensure profitability of the development. The field lies in 146 m of water 7 miles west of the Ninian field.
J. D. M. Tickell and J. E. Smith of Conoco (U.K.) Ltd. outlined the subsea development plans for the Lyell field in a paper presented at the subsea conference.
The evaluation of the discovery and appraisal wells indicated that the field may have some trouble maintaining economic production levels despite the presence of a major oil accumulation. The field is composed of geologically complex formations in the Brent group (Tarbert, Ness, Etive, Rannoch, and Broom). Thus, it was necessary to study all possible production schemes before proceeding with development.
Because of the complex geology, the majority of the development will not have predrilled wells. Rather, the location of each well will be determined by data from an existing 3D seismic survey and by the performance from the previous wells.
A subsea satellite system was chosen over other fixed and floating production systems, predominantly because of the lower capital expenditure of the subsea system. Following production history from the development of Region A of the Lyell field, a decision will be made regarding the higher risk regions of the field.
One major accomplishment was the contract with a third party (Chevron U.K.) to handle the processing and further transportation of the hydrocarbons. The contract for the connection to the Ninian facilities, the first such agreement in the North Sea, helped the economics of the project. The Lyell field may not have become profitable if it required the installation of expensive facilities, the authors say.
The subsea concept for the Lyell field is a diver-installed and maintained cluster manifold arrangement with four flow lines and umbilical to the Ninian Southern platform. The cluster arrangement was preferred over a template because it:
- Increased development flexibility
- Accelerated development drilling and allowed batch setting of conductors and casing strings prior to installation of the manifold
- Provided flexibility for simultaneous drilling and production
- Lowered the initial investment
- Allowed for schedule considerations.
The project management required that any design have a 95% availability of equipment. By obtaining equipment fit for a purpose with few "frills," the project was kept on an aggressive schedule with low costs. Equipment procurement began 2 months after detailed engineering. The pipeline and manifold are scheduled for installation in the second quarter of 1992.
Up to 15 wells will be drilled in a circular pattern on 9 m centers around the manifold (Fig. 2). This pattern reduces the risk of damage from dropped objects. The 28 m spread of the wells around the manifold allows access to all the wells without the repositioning of the anchor spread.
The drilling rig will have a full saturation diving setup on board.
The initial development plan calls for approximately eight producers and five water injectors. The flow lines will include a 12-in. main production line, an 8-in. test production line, a 10-in. water injection line, a 2-in. methanol line, and a single umbilical.
Drilling represents approximately 45% of the total project development cost. To avoid problems with cuttings debris on the manifold and to allow simultaneous safe drilling and production operations, all 30-in. conductors and 20-in. casings are batch set with permanent guide bases and flow line bases prior to manifold installation.
The rig will also be used to hook up the trees to their respective guide bases and the control systems to the jumpers. The Christmas trees are a compact monoblock design-this reduces height and thus any bending moment on the conductor from snagging loads. The manifold design is based on five headers: production, test, annulus, water injection, and methanol.
Production is expected to reach 19,000 b/d with first oil expected in 1993. Following satisfactory performance of Phase I, further development of the other Lyell field regions may be anticipated, the authors say. Thus, an objective of the Phase I drilling program will be to obtain additional appraisal information for the other prospective areas.
In addition to spare flow line capacity, future production will be handled by the following provisions: flow line and umbilical connection, two spare well slots on the main manifold, flexibility to accept and control a directly connected manifold extension for up to four additional well slots, and flexibility for a remote 10-well manifold cluster.
STAFFA FIELD
A small, marginal reservoir in the North Sea, the Staffa field, can be developed economically by tying back the two subsea development wells into a nearby existing platform, according to N. R. Thorpe, F. Moore, and N. Nash of Lasmo North Sea Plc. Lasmo is the majority partner with Ranger Oil (U. K.) Ltd. in the field.
One discovery well and two appraisal wells were drilled in Staffa field in the mid-1980s. The field will ultimately produce crude oil from two development wells, one of which is the discovery well, for approximately 8 years. Initial production rates will be near 8,000 b/d.
The Staffa field is a small Middle Jurassic oil accumulation located in the U.K. sector of the North Sea. Production from Staffa will flow through a pipeline to the Ninian Southern platform (Fig. 1).
Because of the marginal nature of this field, only tried and tested equipment and techniques were used in the development. The cost of the project was kept to a minimum through the use of an uncomplicated design and in-house engineering and project management. Five areas (engineering, drilling, project services, quality assurance, and safety) reported to a project manager, and outside engineering services were obtained only as required. This team concept reduced design man-hours and was used through all phases of development from initial engineering to first oil.
The produced hydrocarbons will be processed at Ninian under a tariff agreement with Chevron U.K. The wells will be tested by alternately shutting in one and metering the other, A supervisory control and data acquisition system on Ninian Southern will monitor the two subsea wells.
The main components of the subsea system include the following:
- Two subsea well production systems (Fig. 3)
- Subsea control system
- An 8.625-in. coated pipeline
- An armored electro-hydraulic control umbilical with three chemical injection hoses
- A subsea emergency shutdown valve and an isolation valve on a skid (shared with a similar system for the future Lyell development)
- An 8.625-in. riser installed in a multiriser caisson retrofitted to the Ninian Southern platform
- A riser emergency shut down valve located on a new deck adjacent to the riser caisson hang off
- A process train with a dedicated feed heater, slug catcher, separator, and metering skid.
The wells will be drilled with 9-5/8-in. casing set just above the reservoir and with a 7-in. liner through the pay zone. The 4-1/2-in. completion tubing and accessories are made of 13% chrome or compatible steel to resist corrosion from the produced CO2.
Because of the high content and partial pressure of CO2 in the well stream, the electro-hydraulic umbilical will continually carry corrosion inhibitor into both tree blocks. A subsea, nonintrusive pipeline corrosion-monitoring system was developed to measure the efficiency of the inhibitor throughout the various stages of production.
The design temperatures range from a maximum of 110 C. expected at the wellhead during the first stages of production to a minimum of 5 C. when the reservoir is depleted. The design will accommodate a maximum shut-in pressure of 4,500 psig and a maximum flowing pressure of 2,600 psig, the authors report.
The subsea trees and associated equipment will be fully interchangeable between the two wells. The existing subsea wellheads had different profiles; thus, wellhead conversion assemblies were necessary. The wellhead conversion assemblies were also required to support a flow line connection spool so that the spool piece would not have to be disconnected prior to retrieving the tree.
The wellhead conversion assemblies provide a new profile to support the tubing hanger (rather than setting the hanger in the existing wellhead).
One of the primary features in the design of this subsea system is the ability to perform simultaneous workover and production operations. During a workover, control of the producing well will remain with Ninian Southern. However, the rig will have an emergency shut down function on board connected by an automatic radio link. A manual push button on the remote emergency shut down panels on the workover rig will effect a complete shut down of the producing well within 20 sec.
To change control of a subsea module from the Ninian Southern platform to a rig preparing for workover, the active tree cap is removed. The lower marine riser package from the rig makes up on the mandrel mating plate and allows the rig to take control. Each tree has a roof below the tree cap mandrel; it protects the tree from small dropped objects but does not interfere with workovers.
The wellhead protection structure is independent of both wells and will protect them from trawl board snag forces of 28 tons. The open topped structure has sufficient clearance to accept a 15,000-psi marine BOP in any wellhead axis.
ALWYN FIELD
A cluster of three subsea oil and gas wells using standardized subsea equipment will allow the economic development of Total Oil Marine's Alwyn North extension project, according to J. L. Rabourdin of Total Oil Marine and A. Embrey of FMC Corp. The three-well cluster is located in 130 m of water about 460 km northeast of Aberdeen in the northern part of the North Sea.
The wells will tie back to the North Alwyn A platform, approximately 5,600 m away.
The three wells will be batch-drilled to minimize blowout preventer and riser handling time and reduce the risk of damage from dropped items on the well cluster.
The subsea completions and subsea Christmas trees are also run using the batch setting philosophy.
Each well will be drilled with a "J" deviation profile with two wells kicking off at 630 m and the third at 1,600 m. The casing programs are similar to those of other Alwyn wells: 30-in. casing at 200 m, 18-5/8-in. casing at 600 m, 13-3/8-in. casing at 2,200 m (top of Cretaceous), and 9-5/8-in. casing at total depth (Brent formation).
A special completion guide base is designed to be run with the 30-in. conductor pipe. This allows subsequent connection of the flow lines to the guide base. By running the completion guide base at the beginning of the drilling operation, more flexibility is obtained for project planning and scheduling. Drilling operations can then be stopped at any time for laving the umbilical and the three flow lines.
The completion guide base can also be run as the first step of the completion phase following the removal of the drilling guide base. The completion guide base has a funnel-down design which allows it to be stabbed over the wellhead without the assistance of guidelines if it is run without a temporary guide base in place.
The guide base also contains a number of flow line components to facilitate interfaces between the tree and the production flow line. Its design incorporates a flow line hub for connection to the tree, isolation valve with remotely operated vehicle (ROV) docking facility, pigging spool for attachment of a pig launcher, and a storage rack for the control jumpers. After the tree is installed, an ROV can easily move the jumpers from the stored position to the production mode position.
Each Christmas tree is a 4-in. x 2-in., 10,000-psi solid block assembly of eight valves.
Five of the valves are remotely controlled from the platform during the production mode; seven are controlled from the installation rig during workover mode. The tree has four pressure sensors, one temperature sensor, and a tree cap which acts as a secondary well pressure barrier (the swab valves are the first barrier).
The Christmas tree configuration has all of the valves integral to the main block, and all of the valves face the same direction. The valves terminate at the perimeter of the tree and have identical interfaces for ease of access by ROV.
The workover riser equipment includes the safety package (with a wire/coiled tubing shear valve block), the emergency disconnect package, the riser and stress joint, and the surface tree (Fig. 4).
The top interfaces of the safety package, the tree cap, and the Christmas tree are identical to allow use of the emergency disconnect package. The emergency disconnect package can accommodate a release angle of 10 offset between the rig and Christmas tree.
To date, all completion guide bases have been installed, and all flow lines and umbilicals have been laid and connected to the guide base.
This completed all diver-assist activities. Two of the wells have had drilling operations completed through setting the 9 5/8 in. casing; the third well is being drilled. Following the drilling operations, the tubing hangers will be batch-set in the three wells and then the three trees will be run.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.