Unforeseen Geology Creates a Need For "an Integrated Team Effort In Geosteering a Horizontal Well to Success In Northwest Australia

Abstract

Abstract West Australian Petroleum Pty. Limited has improved the prospects of further development of a mature oilfield on the, Northwest Shelf of Australia by utilizing horizontal well technology. Combining detailed reservoir characterization and MWD information, a well path initially intended to include 500m of near-horizontal section was redesigned during the course of drilling to adapt to unforeseen changesin the geology of the reservoir due to local faulting. The result was 959m in of horizontal section at 680 mTVD, 400 m of which were in productive interval. The well reached inclinations as high as 103 ° and turned through 30 ° azimuth to run parallel to the field'sbounding fault, transforming a potentially failed wellbore into a success through interactive geosteering. The problem-free drilling of this well has opened the way for newapproaches to developing this mature oilfield. Introduction West Australian Petroleum Pty. Limited (W APET) Operates the Barrow Island oilfield on the Northwest Shelf of Australia for its joint venture participants Chevron Asiatic Limited, Texaco Oil Development Company, Mobil Exploration and Developing Australia and Shell Development (Australia) Pty Ltd. Barrow Islandis located approximately 1,300 Ian north of Perth and 56 Ian off the mainland coast (Figure 1). The Island covers an area of 234 sq. Ian and forms the surface expression of a north-plunging regional anticline that has persisted since the Middle Jurassic. A large normal fault, referred to as the Barrow Fault, truncates the southern end of the anticline forming the southern limit of the trap (Figure 1). The Cretaceous Windalia Sand is the largest reservoir on Barrow Island; covering an area of about 90 sq. Ian, it has over 140 m of vertical closure from 560 to 700 m below sea level (Figure 1). Approximately 30 m thick, the Windalia Sand is subdivided into three main units: two reservoir intervals, the Upper and Lower Sands approximately 17 m and 9 m thick respectively, separated by a 4 m thick silty claystone unit referred to as the Middle Shale. The Upper and Lower Sands consist of fine grained, glauconitic shaly sand, and are further subdivided by thin carbonate cemented sands or tight streaks, typically less than 50 cm thick. Correlations indicate the tight streaks conform with the stratigraphy of the reservoir and are laterally extensive over parts of the field, forming localized vertical permeability barriers. Average porosities for the Upper and Lower Sands are approximately 24% and 21 %, while the average permeabilities are 8 md and 3 md. FIGURE 1. Illustrations Available In Full Paper. However, the better quality parts of the reservoir in both the Upper and Lower Sands have core porosities and permeabilities as high as 28% and 100 millidarcies. Reservoir quality is primarily dependent on the content of glauconite or other clays in the sands. Evaluated oil saturations exhibit a continuous transition from 50% at the crest of the anticline, to around 30% at the present limit of drilling on the flanks.