Since drilling of the very first horizontal well in 2005, more than 1500 horizontal wells have been brought into production in the Devonian-aged Woodford shale gas field in the Arkoma Basin of Oklahoma, USA. In 2008, through a combination of trades and purchases of acreage, BP consolidated its position as the first Major International Oil Company in the Woodford field and has subsequently drilled more than 200 horizontal wells and gained a working interest in a further 981 wells.
Across the field area of more than 3000sqkm, initial stabilised production rates range from 2 to 8 million standard cubic feet per day and estimated per-well recovery (EUR) ranges from 2 to 7 bcf per well. Improvement in the prediction of this highly variable well performance in this unconventional reservoir is seen as critical in the economic design of the field development. To assist in understanding and prediction of this large variation in well performance, BP has designed and applied a number of evaluation technologies that have enabled the integration of well operations data and reservoir characteristics. In a core operations area covering approximately 340sqkm, BP has conducted closely controlled operational experiments in numerous aspects of reservoir management and well completion. These have included research in determination of optimal well spacing, selection of horizontal well lateral lengths and variation in frac stage spacing. Through analysis of all the available production and operational data, it has been possible to construct a Performance Indicator (PI) tool through which production variations across the field could be visualized. This approach has demonstrated that the variation of well performance is best related to geological or more general subsurface trends rather than well-completion or other operational design issues. Integration of these data has enabled BP to significantly improve the accuracy of production forecasts for both short and long-term field performance. Critical elements in the success of this project include key advances in understanding the importance of subsurface structural complexity, the impact and prediction of local variation in the shale reservoir characteristics and the careful management of changes in well design and completion methods. Together, these have enabled the accurate prediction of reservoir geological risk and allowed better definition of specific areas of the field where well performance could be expected to be at its best. Direct benefits of this integrated evaluation have included the the prediction of reservoir performance of new infill wells, identification of areas in the field where development well spacing could be reduced and gaining manangement support for a proposed refraccing programme.