Dr. Rolf Prydz
Senior Vice-President
Norsk Hydro AS, Oslo
The West Troll oil province in the Norwegian North Sea contains large reserves in thin layers, sandwiched between a huge gas cap and an active aquifer. This complex structure inspired the North Sea's most ambitious subsea development to date.
Troll field oil development is the first to rely entirely on production wells with horizontal sections. Its clusters of subsea wellheads will be tied back to the world's first concrete semisubmersible production platform.
Besides all this, the development had to be completed in 3/2 years from approval to production, since oil production had to begin before depletion of the field's massive gas reserves reduces reservoir pressure too much.
Troll field lies in 1,000-1,100 ft of water on Norwegian continental shelf Blocks 31/2, 31/3, 31/5, and 31/6. It was discovered in 1979 by the 31/2-1 exploration well, subsequently found to have drilled into the crest of the large gas structure on West Troll.
By the end of 1984 a total of 15 wells ha(f been drilled, confirming Troll to be a major discovery. Oil reserves in West Troll were recently upgraded to 370 million bbl.
Troll field is covered by two production licenses, each of which is unitized. Owners of license PL 054 for Block 31/2 are Den norsk stats oljeselskap AS (Statoil) 58.8%, AS Norske Shell 25.9%, Norsk Hydro AS 4.9%, Elf Aquitaine Norge AS 3.105%, Conoco Norway Inc. 5.191%, and Total Norge AS 2.104%.
License PL 085 for Blocks 31/3, 5, and 6 is held by Statoil 82%, Norsk Hydro 9%, Saga Petroleum AS 6%, Elf 2%, and Total 1%. Norsk Hydro is operator of West Troll development, and Shell is operator of the East Troll gas project.
APPRAISAL
Appraisal drilling on Troll field revealed estimated reserves of 46 tcf of gas for the entire field. The eastern province adds 3.8 million bbl of condensate to the oil total in West Troll.
Because the oil was contained in thin layers distributed over a wide area, development of the oil reserves was initially considered complex and commercially uncertain. Development activities centered on the large gas resources, which are already under development, although destined like West Troll to come on stream in 1996.
The field is divided into three main areas (Fig. 1). West Troll oil province has an oil column 72-85 ft thick. West Troll gas province has an oil layer 4046 ft thick. The oil column in the East Troll gas accumulation is at most 13 ft thick (Fig. 2).
Though development studies showed that horizontal wells would be the most economic way to deplete West Troll's oil layer, it first had to be proved that it was possible to drill and complete a horizontal well in the highly permeable and unconsolidated sands of West Troll.
TEST WELL PLAN
Planning and drilling of well 31/2-16S began in 1989. The Deep Sea Bergen semisubmersible was chosen to drill and complete the well, and the Petrojarl 1 production ship was chosen for the long term test.
Two main questions were studied during the planning phase:
- What is the horizontal section length and completion diameter required to give the best chance of achieving a high initial rate and sufficient cumulative production to confirm the application of horizontal well technology to the thin oil layers?
- How should the horizontal section be drilled and completed to avoid sand production and achieve a good productivity?
Analytical work showed that the diameter of the horizontal section is an important parameter in the productivity potential of a horizontal well drilled in high permeability sands.
For any given diameter and a chosen set of reservoir parameters there is a critical horizontal section length beyond which further increase in length does not result in further significant improvement in productivity.
However, longer wells were not ruled out as their increased drainage area was still considered attractive.
TEST WELL DESIGN
The team decided it was necessary to drill an 8 1/2 in. diameter horizontal section and complete it with a 6 5/8 in. liner to achieve the necessary production rate and make best use of Petrojarl's 30,000 b/d capacity.
The 13 3/8 in. casing had to be set at a high angle immediately above the reservoir (Fig. 3). In anticipation of hole cleaning problems in the 17 1/2 in. section, the rig was equipped with a 6 5/8 in. drillstring to increase annular mud velocities to assist with hole cleaning.
Troll's high permeability formation necessitated sand exclusion. A 6 5/8 in. prepacked screen was chosen for horizontal completion. This in turn necessitated use of a drilling mud which would maintain hole stability yet still be easily removed after placing of the prepacked screen.
Hydro's R&D group at Bergen designed a salt-saturated mud system which provided a firm filter cake to maintain hole stability during drilling and which could easily be removed later by washing with fresh water.
The well was spudded September 1989 and drilled and completed with a 1,600 ft long horizontal section. An 11 month production test was started in January 1990.
The test well confirmed both the operational feasibility of drilling and completing horizontal wells in West Troll oil province and their suitability for developing its oil reserves.
GAS PROVINCE WELL
The success of the oil province test well suggested the application of horizontal technology to development of the 40-46 ft oil layers in West Troll gas province. Again, it was decided to drill a test well.
Well 31/5-4S was similar in design to the oil province test well, though its horizontal section was longer at 2,600 ft. A 4 month production test was run with Petrojarl, with results close to the lower limit of what was considered necessary for economic production.
However, a period of supercritical production sustained higher rates, and reservoir simulation studies indicated a potential for increased recovery when producing at supercritical rates.
Despite the muted success of the well, the oil resources of the gas province still represent an economic potential. Based on the current geological model and reservoir simulation, five areas in the West Troll gas province are considered to have commercial oil production potential (Fig. 4).
DEVELOPMENT STUDIES
Development options involving 12-21 wells with horizontal sections between 1,600 and 2,600 ft were studied, with combined oil production in the range of 95,000-160,000 b/d.
A development comprising 17 wells with 2,600 ft horizontal sections to give 160,000 b/d output was found to be the optimum. Refinements of the study suggested the number of wells should be raised to 18, while reinjection of produced associated gas would counteract the movement of the fluid contact and improve oil recovery by about 10%. Hence a permanent gas injection well connected to one of the oil province subsea manifolds was built into the development plan.
To reduce seabed congestion and number of flow lines, wells were divided into groups of six to be tied back to manifolds, which were in turn connected back to the floating production facility.
Because of the large area covered by the oil layers, it was necessary to design unconventional well profiles so that satellite wellheads could be placed close to manifolds.
Drilling engineering studies supported drilling of a 3D well path, whereby angle is first built into one plane and the well path turned to obtain the required orientation for the horizontal section (Fig. 5).
Besides allowing wellheads to be placed closer to the manifold for any target reservoir, this technique reduced the number of rig moves required during development drilling, allowed the use of conventionally anchored rigs, and reduced subsea flow line costs. The final subsea layout had capacity for 26 wells.
SUBSEA CLUSTERS
A subsea cluster concept was the building block for development, centered around a manifold center with a retrievable manifold module (Fig. 6). Three way valves direct well flow.
Each wellhead installation comprises a Christmas tree module with dual bore Christmas tree, choke, valve controls, and a trawl net protection structure. Parallel gathering lines from the manifold center connect to an integrated riser base, from where oil will be taken through flexible risers to the production facility.
Combined services and control umbilicals supply hydraulic and electric power, transmit control and monitoring signals, and supply methanol and corrosion inhibitor to the wellheads for hydrate prevention during cold start-up.
Further appraisal is planned for West Troll gas province. Any reserves confirmed will be phased into the oil province development. The gas province oil reserves will be developed under the subsea concept chosen for the oil province. Tenders for construction of gas province subsea equipment have been received.
To provide extra capacity for future development of the five oil zones of the gas province, the production unit is being designed with riser capacity for up to nine subsea clusters to operate at once, four in the oil province and five in the gas province.
PRODUCTION FACILITIES
West Troll field oil process facilities comprise a three phase, two stage, single train separation system. Produced water will be cleaned to 40 ppm oil in water using hydrocyclones before being discharged to sea.
The West Troll gas processing plant will be able to handle 180 MMcfd at plateau production, rising to 250 MMcfd afterwards.
Both turret-moored ship and concrete semisubmersible vessel structures were considered for the processing unit during the development planning stage. The semisubmersible was the favored option based on cost, schedule, and regularity considerations.
It was originally decided to export oil by means of offshore loading to tankers, with oil storage for 4 days, plateau production to be provided in pontoons.
Further analysis of the concrete substructure, however, indicated that the effect of second order harmonics required a larger substructure with larger draft than was anticipated.
In May 1992 it was decided to drop the requirement for offshore storage and loading in favor of either direct offshore loading or pipeline export.
Redesign of the substructure was carried out, and the removal of the oil storage reduced the required concrete volume by about one-third. However, compared with the development plan estimate the substructure has an increased concrete volume of about 20% as safety features such as double wall columns have been added.
West Troll gas province wells are predicted to produce large amounts of water. Hence capacity of water treatment facilities has been raised from 25,000 cu m/day for oil province requirements to 40,000 cu m/day.
DEVELOPMENT PLAN
In December 1991 the Troll licensees submitted a plan for development and operation (PDO) for the Troll oil province. This proposed the use of 17 horizontal wells, completed subsea and tied back in groups to a concrete floating production platform (Fig. 7). The PDO was approved in May 1992.
Detailed design of the concrete substructure is in progress. In January, Hydro let a $310 million contract to Kvaerner AS, Oslo, for construction of the concrete hull. This followed a decision to seek bids for alternative steel designs after the estimated price of a concrete hull rocketed (OGJ, Feb. 1, p. 23). This helped put the budget up from the original estimate of $2.2-2.5 billion.
Kvaerner is to complete construction of the hull in October 1994. Topsides will be lifted onto the hull February 1995, with hook-up due for completion in time for towout to the field in September 1995. First production is expected Jan. 1, 1996.
In july, Hydro let an 800 million kroner ($108 million) contract to Polar Frontier Drilling AS, Bergen, for drilling in West Troll oil province. The Polar Pioneer semisubmersible will drill and install subsea equipment beginning Mar. 1, 1994.
OIL EXPORT
The four alternatives for oil export eventually considered were direct offshore loading and 16 in. diameter pipeline to the Sture, Mongstad, or Kollsnes terminal on Norway's west coast (Fig. 8).
Direct offshore loading and a pipeline to Kollsnes were rejected on a cost basis. Pipeline exports to Sture and Mongstad were both considered feasible.
The pipeline route to Sture is relatively simple and previously qualified by the Oseberg field-to-Sture pipeline. However, terminal modification costs and tariffs at Sture would be an addition.
Terminal modification costs and tariffs for Mongstad would be lower, but the pipeline route would have to cross a 1,800 ft deep trench (Fig. 9). It was therefore technically difficult and introduced cost, schedule, and safety uncertainties.
Despite the technical challenges, the majority of Troll license partners decided on the Mongstad route in the end. A development plan was submitted, by a pipeline joint venture with Statoil as operator, to the Ministry of Industry & Energy in MaN,. It outlined a $125 million project which will involve laying pipe at greater depth than any existing pipeline on the Norwegian continental shelf.
Lately, however, evaluations made by the Norwegian Petroleum Directorate on behalf of the Ministry of Industry & Energy have raised serious questions as to the safety, cost, and schedule of the Mongstad pipeline project.- NELSON OIL FIELD To
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
