This paper describes the development of a low-solids mineral oil-based fluid and its successful application as a drill-in and completion fluid in a multilateral (MLT) well on Statoil's Aasgard field, off Mid-Norway. The introduction of highly complex technology, such as multilateral well design with long horizontal reservoir sections, demands a strong focus on the drilling fluid characteristics. Recent field experience showed that conventional oil-based mud (OBM) systems had limitations, when used in a demanding downhole environment influenced by elevated temperatures and ambitious drilling and completion objectives. This resulted in lower than expected drilling efficiency and well productivity. Accordingly, a development program was instituted to qualify a new high temperature OBM that possessed reduced formation damage potential and superior bridging characteristics while remaining thermally stable. The candidate fluids investigated were OBM of three different types:standard OBM with a mineral base oil,OBM with a linear paraffinic base oil anda low-solids (LS) OBM. The latter was based on an emulsion with a heavy calcium bromide brine as the internal phase and a mineral base oil as the external phase. Bridging materials and organoclay for viscosity were added as the only solids materials. The results of the qualification programme showed that the LS OBM exhibited superior sag stability and much higher return permeability values as compared to the two other oilbased alternatives. The field application of the fluid was very successful. And the Aasgard subsurface team managed to drill and complete a total well path length of about 4900 m. The well was drilled and completed 37 days ahead of plan and produces with a productivity index as expected. Introduction The Aasgard field development is located in the Haltenbanken area off mid-Norway and comprises three fields - Smørbukk, Smørbukk South and Midgard. The field was developed in the late 1990s with a subsea production system with two production facilities, Aasgard A (FPSO) and Aasgard B (semi submersible gas processing platform). In addition a storage and offloading vessel (Aasgard C) receives the liquid production from Aasgard B (Fig. 1). The three different fields have widely different fluids and reservoir quality, and accordingly, wells are completed differently. The Smørbukk reservoir is the most challenging with a reservoir temperature of 165°C in the deepest zones. Smørbukk South is somewhat shallower than Smørbukk and the reservoir temperature is 150°C in the deepest zones. The Midgard field is different again from both Smørbukk fields-the reservoir temperature is lower at 90°C and a different approach to drill and complete the reservoir has been adopted. This paper concentrates on the two Smørbukk fields. Additional information on geology, reservoir engineering aspects and early production strategies of the Aasgard field and field-specific technology challenges was reported by Haaland et al. (1996)1. Well constructions in the early development phase followed a rather straightforward design. In general, the Smørbukk wells were drilled vertical or deviated and the Smørbukk South wells were drilled horizontal. Completions consisted either of cased and perforated reservoir sections (Smørbukk) or openhole completions with pre-drilled liners (Smørbukk South). All Smørbukk wells are commingled wells, the Smørbukk South wells targeted the Garn formation only. Although experience with multilaterals (MLT) was limited in the mid-90s, multilateral wells with long horizontal sections were part of the long-term field development plan for production of the Ile and Tilje formations on Smørbukk South 1. MLTs were considered essential to maximize drainage from a reservoir with rather poor quality. With increasingly demanding well construction plans, work processes and system components for drilling and completion operations need to be continuously revised. Under high-temperature conditions all elements in the well construction process must be highly redundant and compatible.

Four expandable completion liners (ECLs) have been run in Algeria in two fields-these are the first fully compliant ECLs in Algeria, the first worldwide in gas wells, and the first worldwide in multilateral wells (from Weatherford database). This paper presents the first detailed benchmark study of ECL performance.All systems to date have been run in 8½-in. hole using 5½-in. base-pipe ECL compliantly expanded, and the installations went well. It has been possible to compare ECL performance data against a comprehensive surveillance data set for the two fields where data from existing openhole completions allow meaningful comparisons. The other completions consist largely of slotted liners and some barefoot completions. The tested production rates in each of the wells have been high relative to normal field trends; however, the predominant factor in this is the reservoir character. Pressure-buildup (PBU) analysis indicates that the second well has reduced Darcy skin, while it is considered unproved in the first well (more data over time are needed). There is, however, consistent evidence for a reduction in the rate-dependent proportion of total skin in both wells. This is supported by other studies and a consideration of basic principles.The reduction in the rate-dependent proportion of skin has given an increase in production rate of 5-20% as compared with the computed rate from a slotted liner. This difference assumes no borehole collapse, with analyses and discussion presented of the effect on well performance should borehole collapse occur.The joint venture (JV) is investigating the further use of this technology in smaller hole sizes and possibly in conjunction with fracture stimulation. Reservoir DescriptionsThe In Salah gas reservoirs are sandstones of Devonian and Carboniferous age. They are hard consolidated sandstones with generally low-to-moderate permeability. The fields typically have multiple sands units that are laterally extensive. The gas is dry, comprising 90-98% methane. CO 2 content varies from 1% in the Carboniferous to 10% in the Devonian reservoirs.Teg is a large four-way dip closed structure with few faults. The infill wells are in the Devonian D55 (Emsian-tidal/shallow marine sand), lower D40 (Siegenian-predominantly clean fluvial sand), and upper D30 (Gedinnian-tidal/estuarine sand/shale) sandstones. The Devonian reservoirs are fluvial to shallow-marine sandstones. Reservoir quality is usually good, with porosities up to 27% and permeabilities up to 150 md, and the sands are laterally well connected. Gas in the Devonian at Teg contains typically 90% methane with 9% CO 2 and 11 ppm H 2 S. The dewpoint at 29 bar is -46°C, water/gas ratio (WGR) is 2 bbl/MMscf, and condensate/gas ratio (CGR) is 0 bbl/MMscf. The Reg field consists of a large four-way dip closed structure covering an area of up to 350 km², which is elongated in a northwest/southeast orientation. A 3D-seismic survey acquired by the JV during the appraisal phase over the crest of the field has confirmed that the structure is exten...

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Four expandable completion liners (ECLs) have been run in Algeria in two fields - these are the first ECLs in Algeria, the first worldwide in gas wells and the first worldwide in multilateral wells. This paper is the first detailed benchmark study of ECL performance. All systems to date have been run in 8 ½″ hole using 5-1/2″ base pipe ECL compliantly expanded, and the installations went well. It has been possible to compare ECL performance data against a comprehensive surveillance data set for the two fields where data from existing openhole completions allow meaningful comparisons. The other completions consist largely of slotted liners and some barefoot completions. The tested production rates in each of the wells have been high relative to normal field trends; however, the predominant factor in this is the reservoir character. PBU analysis indicates that the second well has reduced Darcy skin, while it is considered unproven in the first well (more data over time is needed). There is, however, consistent evidence for a reduction in rate-dependent proportion of total skin in both wells. This is supported by other studies and a consideration of basic principles. The reduction in the rate-dependent proportion of skin has given an increase in production rate of 5-20% as compared to the computed rate from a slotted liner. This difference assumes no borehole collapse, with analyses and discussion presented of the effect on well performance should borehole collapse occur.

No abstract