Perforation and Flowback Highlights From the Gorgon Field, Offshore Australia

Abstract

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182420, “Perforation and Rig Flowback Highlights for the Gorgon Field Development Wells,” by A.K. Morrison, SPE, and J.P. Beinke, SPE, Chevron Australia, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed. The Gorgon liquefied-natural-gas project (Fig. 1) is one of the world’s largest natural gas projects and the biggest single resource development in Australia’s history. In 2014, eight Gorgon wells were perforated successfully, intercepting between three and seven commingled zones and gross intervals of up to 500 m per well. This paper contrasts the detailed perforating and flowback plan with the results of the operation where a number of planned, and some unplanned, contingencies were faced. Perforation Basis of Design The main element of the Gorgon- project well design that affected perforating was that reservoir sections would be completed with a cemented 70-in. liner in 8¾-in. open hole, with the top perforation approximately 250 m below the liner top. Each well was to be completed in multiple formation zones, with the average gross perforation interval per well (top to bottom shot measured distance) expected to be more than 400 m and an average net perforation interval (sum of perforated zones) of close to 150 m. Four perforating alternatives were evaluated with respect to their relative operational and subsurface risks: Tubing-conveyed perforating (TCP) shoot and drop—guns deployed into the liner on a gun hanger before upper completion is run and then fired and dropped after perforation TCP shoot and pull—a separate drillpipe-conveyed perforation trip before completion with use of a sized kill pill after perforation to mitigate losses before the upper completion is run Coiled-tubing conveyed Wireline conveyed After analysis, the TCP shoot-and- drop option was eliminated because of the additional time and well-control risk of drilling the required rathole to accommodate dropped guns. Shoot and pull was not considered a viable option because of a lack of a temperature-rated, post-perforation kill pill. Coiled tubing was rated feasible but with inherently greater operational risks when performed from a mobile offshore drilling unit. The process concluded that the wireline-conveyed method was the best solution despite requiring several perforating runs per well. Operational issues associated with this technique were identified, and plans were developed for these to be managed safely. The gun length per trip was expected to be approximately 30 m, necessitating at least five wireline trips to perforate each well, with each run expected to take between one and two rig shifts. In the event of failure (e.g., unsuccessful cable development), the selected contingency method for deployment was coiled tubing, which was considered a proven alternative.