Monobore Completions and Novel Wireline Perforating of High-Angle Wells in the Nelson Field
Authors: Griffin P.G. , Fowler N.M. , Wenk A.D. , Roland Hamp , Grant David 
Published: December 2007

The Nelson field gas-lift completions were designed to optimize production, enhance safety and reliability, and minimize well-maintenance costs. The completions are of a near-monobore design and include an annular safety system, which is regarded as a major safety benefit during gas lift. The single-trip completions were batch installed in eight high-angle (up to 70°) predrilled wells. This paper presents details of the completion design and the approach taken to planning and installing the completions. The paper also describes the use of a novel technique for perforating the platform wells with wireline guns.

Nelson Field Overview

The Nelson field straddles U.K. Continental Shelf Blocks 22/11 and 22/6a of the Central graben of the central North Sea, ˜112 miles east of Aberdeen (Fig. 1). Enterprise Oil PLC discovered the field in 1987 following the drilling of Well 22/11-5.

Geologically, the field comprises a broad dome-shaped structure of Paleocene sediments draped over fault blocks containing early Permian and older rocks. The reservoir interval comprises the Forties sandstone member of the Sele formation. Trap is provided by four-way dip closure of overlying Balder and Sele mudstones. The structure lies at 7,200 ft total vertical depth subsea (TVD SS) and has a maximum oil column 250 ft in vertical thickness. Most of the reservoir oil column is perforated in the production wells except for short sections straddling shales, which will be used as vertical permeability barriers for future water shutoff. Production wells have perforated intervals of up to 330 ft measured depth. The reservoir quality is good, and the wells are capable of high initial production rates of up to 25,000 BOPD.

The Nelson reservoir is normally pressured at initial conditions and will require gas lift to sustain production rates as reservoir pressure is depleted and water breakthrough occurs. Oil recovery will be maximized by water injection through the periphery of the field, which will supplement natural waterdrive from the underlying aquifer.

The field is developed from a single, fixed, steel jacket at the center of the area, which stands in 280 ft of water. A subsea satellite development to the south is tied back to the platform (Fig. 2). Platform development wells are drilled at inclinations of up to 70°, giving an effective drilling reach of 3.7 miles. Fig. 3 shows a typical well. Locations outside this drilling reach, at the southern extension of the field, are accessed from the subsea satellite development. Twenty-four production wells, including four drilled at the subsea satellite, and seven water injectors are planned.

Reservoir fluids are processed on the platform by means of a single-train separation system with a 160,000-BOPD and 65-MMscf/D capacity. These fluids have the potential to cause sweet corrosion after water breakthrough; therefore, corrosion resistant alloys have been used on the wetted surfaces of downhole and surface equipment. Stock-tank oil has a gravity of 40°API and is exported to Kinneil through the Forties oil-pipeline system. Reservoir crude GOR is ˜470 scf/STB, and gas is processed through a three-stage compressor. Recovered natural gas liquids are spiked back into the export crude. Gas is exported through the Fulmar gas pipeline to St. Fergus and is also supplied to the gas-lift header for distribution to the wells. Table 1 shows the key field parameters.

The 36-slot platform jacket is a lightweight steel structure (8,500 tonnes) installed over an eight-slot subsea template that supports the 9,500-tonne integrated deck. While the jacket and topsides were being fabricated, eight production wells were predrilled through the subsea template from a semisubmersible. After platform installation, tieback and completion operations ran concurrently with hookup and commissioning operations. In this way, sufficient time was gained to tie back and complete three of the eight predrilled wells between commissioning the drilling systems and gaining approval to start production.

The three wells ready to produce at first oil were batch perforated in quick succession, allowing production to start ahead of schedule on Feb. 18, 1994, with a capability in excess of 75,000 BOPD. Since first oil, the remaining five predrilled wells have been tied back, completed, and perforated. Peak production capacity of 160,000 BOPD was reached 5 months after starting completion operations.

Production-Well Completion Design

In common with many North Sea oil fields, Nelson production wells are initially naturally flowing but, with time, will need to be gas lifted to accelerate production and increase recovery. In conventional gas-lift completions, the production tubing/casing annulus is filled with high-pressure gas that is present from below the tubing hanger to the lowest side-pocket mandrel. On Nelson, we judged this design to be unacceptable because of the risks associated with the increased hydrocarbon inventory from gas lift. These risks are now well recognized and have led to the development of various types of annular safety systems. At an early stage, we recognized that the inclusion of such an annular safety system in the Nelson wells would provide a major safety benefit.

A number of options existed for the provision of such an annular safety system with application for the Nelson platform producers. We used a mathematical technique known as dynamic risk analysis1,2 to decide among these options. This demonstrated that a dual-string system provides significant safety benefits over the more common, single-string concentric annular safety system. These benefits are largely attributable to the fact that high-pressure gas is no longer present below the tubing hanger but is retained by an annular safety packer set several hundred feet below surface. Unlike the single-string concentric design, the surface annulus and wellhead therefore remain unpressurized under normal conditions. This in turn increases system reliability and allows early detection of downhole equipment failure. Having identified the safety benefits of such a system, work proceeded by examining the associated costs.

Economic analysis of the various options was conducted on a "life-of-well" basis. Such analysis includes the timing and impact of workovers and well downtime. When examined on such a basis, the dual-string annular safety system could be shown to be justified economically, although it required a higher initial capital expenditure. The design finally chosen consisted of a dual Christmas tree and dual-string upper completion (with tubing-retrievable safety valves in each string) connected by a parallel flow head to a concentric-type packer set ˜1,000 ft deep. The upper completion required 10 3/4-in. casing to be run to 1,500 ft before crossing over to the conventional 9 5/8-in. production casing (Fig. 3).