Integrated technologies exceed well placement challenge

Abstract

The challenge to place wells accurately within the thin oil column of the Andrew Field has been met through the integration of drilling and data acquisition technologies in the subsurface and well engineering teams. The requirement for accurate placement derives from the need to optimize cumulative oil from each of the horizontal oil producers in the field prior to the inevitable break through of gas and water from the gas cap and aquifer, respectively. This critical requirement was captured as a Minimum Performance Standard for the Andrew well engineering alliance, which provided a focus for the team. It was met through using the Gas-Oil Contact as a local datum to reduce depth uncertainty and downhole engineering including a steering assembly with near bit directional and formation evaluation sensors. At the same time it was also important that a full, comprehensive and quality dataset that could be used for future well and reservoir management decisions be acquired in the wells. This necessity was met through integrated acquisition of data in both LWD and wireline. The data acquisition and well placement challenges converged in the last of the pre-drilled wells, A04, in which geosteering was adopted to change the stand-off about halfway along the well. Introduction The Andrew Field, a Palaeocene deep sea sandstone reservoir containing some 112 mmbbls of recoverable oil was sanctioned for development in 1994. The sanction case for the field centered on the exclusive use of horizontal wells to reduce well numbers and increase oil rates. Horizontal wells were perceived as appropriate because the field has a thin (58 m True Vertical Depth, TVD) oil column overlain by a gas cap and a large active aquifer. Vertical wells in such a reservoir are incapable of producing at sufficiently high and sustained oil rates to be commercially viable. The support for the case came from a well flow test performed on well 16/28-16z, a horizontal appraisal well drilled in 1993. The test data from this well, particularly the relatively high flow rates at low drawdowns and the lack of pressure depletion during flow, indicated that the Andrew reservoir has a generally high Kv/Kh and is conducive to depletion by horizontal wells. This very successful appraisal well allowed the required well numbers to be more than halved from the previous development model which involved 24 conventional vertical wells. This breakthrough, together with the integration of preselected Alliance partners to optimize the facilities, and the use of a Reservoir Uncertainty Statement (RUS) to express openly the subsurface risks to the project value, allowed the project to be sanctioned. Andrew is now to be a development with 10 horizontal wells and one gas injector (Fig. 1). Four of these wells, including the horizontal appraisal well, have been pre-drilled through a template from September 1995 to January 1996. A well engineering alliance, involving BP, Baker Hughes INTEQ, Schlumberger Transocean and Santa Fe as the main members, was set up to construct and manage the wells. Each oil production well is expected on average to recover about 1 mmbbls and hence represents an asset in itself. The wells will be produced at rates higher than the critical rate which induces gas and/or water coning. Therefore the value of each well is strongly influenced by how much oil can be produced before breakthrough of gas and/or water. The challenge therefore for the development team in the template phase of drilling in 1995/6 before first production was to place the wells in the optimum position given the current level of reservoir understanding. Moreover, adequate data sets needed to be gathered from these wells to further reduce the uncertainty in the vision of the reservoir size and internal heterogeneities. This paper describes the integration of well placement and data acquisition technologies to meet this challenge. Business Objectives Well placement. In the thin oil column gas and water are expected to cone into the horizontal wells within 12 months. Critical coning rates are estimated to vary from 800 to 7000 bopd, in contrast to the Andrew oil producers which must produce at average rates of 15,000 bopd to be commercial. Gas and water will break through from the gas cap and aquifer, respectively during the wells' lives. P. 405