Optimizing Development Costs by Applying a Monobore Well Design

Abstract

The An Aike-Barda Las Vegas field, located in the Austral basin 80 km west of Rio Gallegos, Argentina, represents an important discovery in basin development in recent years. The field is an important Springhill formation gas reservoir at an approximate depth of 3100 m and with static pressure of 4400 psi. Gas rates are up to 1 MM m3/d/well. Drilling appraisal and development wells requires the optimization of every operation involved. In this context, improvements in well construction and completion methodology are important contributions. Original well design included 13 3/8-in. surface and 9 5/8-in. and 7-in. casings, with a permanent packer and 4 1/2-in. tubing. The new monobore well design reduces the diameter of each drilled section, narrowing to a 4 1/2-in. monobore installation through the pay zone. The rigless completion includes coiled tubing. Before adopting the design change, potential risk analyses were made to account for the possibility of future reentries and for simultaneous development of a second target (Magallanes formation) at 1700 m. The final well design model showed a cost savings of 30 percent, a sizeable impact on the economics of this project. History The Springhill formation gas reservoir at a depth of 3100 m produces up to 1 MM m3/d/well and has a static pressure of 4400 psi. Fig. 1 shows the stratigraphic sequence of the An Aike field. Above the Springhill is another productive formation called Magallanes. Magallanes is an oil and gas reservoir with a static pressure of 2500 psi at 1700 m depth. So far, this formation has not been developed. The first wells of the An Aike field were drilled to 600 m with 13 3/8-in. surface pipe; 2000 m of 95/8-in. intermediate pipe, to case the Magallanes formation; and a 7-in. production liner in 8 1/2-in. hole, to total depth, through the Springhill gas-producing formation (Fig. 2). Drilling Several alternative designs were considered in order to reduce cost, with special focus on the completion requirements. The analysis of possible wellbore size reduction led to the design of the AA-6 well, with 30% savings as shown in Fig. 8. This well was cased to 600 m of 9 5/8-in. surface pipe; 2000 m of 7-in. intermediate pipe; and a 4 1/2-in. production liner in 6 1/8-in. hole at the total depth, through the Springhill gas-producing formation. This reduced diameter well configuration schematic is shown in Fig. 3. The time/depth curves of these wells before and after the changes (Fig. 4) show that rig time and costs were significantly reduced with the new reduced diameter design (Fig. 5). Down to 2000 m, the on bottom rotating time was reduced by 3.3 days, by drilling an 8 1/2-in. versus 12 1/2-in. borehole (Fig. 6). Spud to the total depth, rig time was reduced by 9 days (Fig. 7). Rig time had the greatest impact on the total cost reduction, as shown in Fig. 5. Reduced requirements for mud and tubular goods were also significant factors in containing overall well costs with the reduced diameter design. The AA-3 and AA-5 wells were drilled with the first design (Fig. 2), AA-6 was drilled as shown in Fig. 3, and the AA-8 and AA-9 wells were drilled with the new design shown in Fig. 10.