The Njord Field is one of the most complex reservoirs in the Norwegian North Sea due to a large number of faults. Seismic quality in the heavily faulted areas is poor making seismic interpretation difficult. Typically the uncertainty in top structure is in the order of 10–100 m.
The well design criteria on Njord are dependent on the structural uncertainty and the availability of new technology. Njord started with relatively simple single-bore horizontal wells. This design was not suitable in the intensely faulted areas. High amplitude U-, S- and W-shaped wells have been effective to penetrate all reservoir units in uncertain areas, to minimize the risk of hole-instability and to drain oil from multiple fault compartments.
The need for placing a well in the best reservoir interval, to penetrate longer reservoir section and to drain oil from sparsely located undrained compartments led to drill a tree-branched well in the recent days. A new active visualization assisted geo-steering technology coupled with biostratigraphy has been tremendously successful to steer the well path in the most complicated area. Another well has been drilled in another heavily faulted area where the pressure depletion in some of the compartments was in excess of 300 bar.
The drive for a cheaper way of drilling sparsely located relatively smaller undrained pockets led to initiate a new campaign to find and drill low cost infill targets using the Through Tubing Rotary Drilling technology. Intensive research and development activities have been undertaken to resolve outstanding issues, such as, protection of X-mas tree and down hole safety valve, risk for mud loss and differential sticking, zone isolation by swell packers, etc.
This paper summarizes the reasons for adopting so many different well types, and a comprehensive description on their planning, execution, challenges, successes and failures.
Introduction
The Njord Field is located in the Haltenbanken area of the Norwegian North Sea approximately 130 km northwest of the operations base in Kristiansund (Fig. 1). The field is situated in the southern part of block 6407/7 and straddles into the northern part of block 6407/10. However, the commercial reservoir is comprised of three main areas in block 6407/7, namely, the eastward dipping eastern area called the East Flank, the crestal part of the structure called the Central Area and the northward dipping northern part called the Northern Area (Fig. 2). No hydrocarbon discovery has so far been made in block 6407/10.
The field was discovered in late 1985 by the exploratory well 6407/7–1 in the East Flank and was subsequently appraised by well 6407/7–2 in the Central Area, 6407/7–4 in the East Flank, and 6407/7–3 and 6407/7–5 in the Northern Area within a time frame of 1986–1991 (Fig. 2). Wells 6407/7–1, 6407/7–3 and 6407/7–4 encountered hydrocarbon-bearing formations of Middle Jurassic Ile at the top, Lower Jurassic Tilje in the middle and Lower Jurassic Åre at the bottom. Hydrocarbon-bearing Ile and Tilje, and water-bearing Åre were found by well 6407/7–2. Commercially viable test oil productions were observed from the Tilje reservoirs in 6407/7–1, 6407/7–2 and 6407/7–4 wells. However, well 6407/7–3 penetrated a much thinner oil pay while the area appraised by 6407/7–5 was water bearing. Therefore, no economically viable resource was immediately foreseen in the Northern Area.
A plan for development and operation (PDO) was approved in February 1995 based on production of the oil resources from the Tilje Formation of the East Flank and the Central Area. However, enough flexibility was introduced in the plan to produce the additional (technical) oil resources in the Tilje Formation of the Northern Area, and oil resources in the Ile and re Formations if proved economically viable. The PDO expected stock tank oil originally in-place (STOOIP) was estimated to be 101.3 million Sm3. The expected recoverable oil reserves were 31.6 million Sm3 corresponding to a 31 percent overall recovery factor. A production plateau rate of 12480 Sm3/d was foreseen. The technical oil resources were estimated to be 39.6 million Sm3 with 4 to 6 million Sm3 of recoverable reserves.
