Big Bore Completion and Sand Control for High Rate Gas Wells

Abstract

This paper outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow unconsolidated sand stone reservoirs. The main challenge in terms of completion architecture was to maximize the well head flowing pressure while insuring "long term integrity" of wells. This was addressed through implementation of limited - or even not - proven technologies. Introduction TOTAL AUSTRAL operates the Carina and Aries fields, located in offshore Tierra del Fuego in the most southern region of Argentina (Figure 1). These fields are prolific gas fields and are being developed with a reduced number of wells, with departures of up to 4 Km @ 1500 m TVD/RKB. The drilling scenario for Carina/Aries phase 1 included two horizontal wells to be drilled from the platform CARINA-1 (85 m water depth) and two horizontal wells from the platform ARIES (65 m water depth) for a targeted production plateau of 12 MSm3/d of gas with 3 to 4 MSm3/d by well at relatively low pressure (80 bars WHFP). Maximizing the Wellhead Pressure The surface project includes the two platforms respectively located at 80 Km and 30 Km from shore, one 24″ main multi-phase sea line from CARINA-1 to Rio-Cullen production facility and one secondary 18″ line from ARIES jacket to the main pipe. The production scheme does not include offshore compression (Figure 2). In this context, limiting pressure drop from the sandy reservoirs up to the wellhead was paramount. Productivity oriented sand control technique and a 9″5/8 production tubing was then selected to maximize and ensure sustained wellhead pressure while minimizing the CAPEX. Flow Insurance Well "longevity" was another "key word" for the following reasons:Limited number of wells.Huge cost of work-over linked with rig and service equipment availability/mobilization because of extreme remoteness of the location (rig not scheduled in the area before five years after the end of current Total Austral drilling campaign). A Challenging Context Developmental problems to fulfill the above well requirements included:No or few case history for 9″5/8 completion and high velocity gas well horizontal sand control.The Extended Reach Departure nature of wells (Figure 3).A tight schedule between the drilling "go ahead" and the request for first gas delivery (18 months).A harsh environment location, remote from any offshore oilfield, over a day's sailing time to reach the operational base (Punta Quilla), in a tax free area with associated administrative issues, making logistics critical (Figure 4).Build/Re-build a learning curve (last Tierra del Fuego offshore campaign in 1997) with limited number of wells. Minimizing Technical Risk This was done through several actions:Purchase "best in class" products".Perform detailed and extensive Factory Acceptance Tests (FAT).Setup a workshop in the operational base, including a mobile test bunker and bucking machine to re-test all the critical assemblies before sending offshore.

Design, Qualification, QAQC and Operational Performance of Completion Fluid, Reservoir Drill-in Fluid and Breaker - Tamar, Offshore Israel

“…The primary scope of the study was to review existing developments to understand field proven designs. The study focused on a global review 2,3,4,5,6,7,8,9,10,11,12,13,14,15,18 of ultra-high rate gas wells which included nine (9) areas and over 130 wells. 16 This study, combined with the experiential knowledge of the team, resulted in a design that integrated the field proven lower…”