In mature fields, hydrocarbons may become "trapped" below the main production zones. These overlying formations may be produced to a very low pressure, while the smaller trapped reserves may remain at virgin pressures or be slightly depleted. Drilling the depleted reservoirs requires a low mud weight to prevent losses and avoid either lower reservoir influx or shale collapse. Due to the often marginal size of the trapped reserves, reducing well costs is critical to project economics. One obvious solution is to deepen an existing producing well and commingle the production from the reservoirs, thus reducing cost when compared to a new dedicated well. Three novel technologies have been identified that, when combined, would allow wells to be deepened at low cost and without severe losses. These include through-tubing drilling,aphron-based drilling fluid, and real time ECD modelling. This paper describes a project where these technologies were applied. Owing to the high-risk nature of the project and the need to protect existing production from the chosen well, in-depth planning and staged implementation of the new technologies were undertaken. A comprehensive risk management procedure was developed and careful testing and data gathering undertaken. The well was successfully executed within planned time. The authors will outline the theoretical and practical aspects of the technology selection criteria, risk management aspects, and how all these were combined to deliver a successful well. Introduction The near vertical (20° inclination) North Sea gas well was producing 200,000m3/day from the upper reservoir zone. The upper reservoir zone, which has been producing for more than 20 years, was depleted from original field virgin pressure of 366 bar to 50 bar. The target lay beneath this depleted reservoir with a thick (40m) claystone layer in between that contains intermittent sand lenses. Throughout most of this field the lower reservoir is below the gas water contact. Thus, the majority of the field only drains the upper reservoir zone. The only well that previously produced from the lower reservoir had watered out. Consequently, in order to avoid the water leg, the plan was to target the remaining reserves in an up-dip location. Therefore, only a relatively small amount of reserves are in the lower reservoir, especially when compared with reserves in the upper block. However, it was perceived that if the well could be deepened inexpensively, it would be an attractive project. The target reservoir had been drained by one production well until it had watered out after eight years of production. It was not clear exactly how much had been produced from this lower reservoir zone, but the pressure was believed to be ca. 250 bar. Additionally, it was believed that the sand lenses in the claystone layer, due to their discreet nature, might be at virgin pressure (366bar). The top of the claystone layer was anticipated to sit 17m below the 41/2-in. shoe (see Figure 1). Challenges This section discusses the challenges that were encountered in the design and execution of deepening the well. These challenges are divided into two categories, namely technical and non-technical challenges. Technical challenges Described below are the technical challenges that were realized during the planning phase of deepening the targeted well.Shale Stability One of the main technical challenges was to maintain shale stability while deepening. Hence, since the shale potentially contains virgin pressured sandlenses, an on-balance situation had to be maintained in the shale during the entire deepening process. However, this requirement increased the chance of fracturing the upper reservoir, because depletion had reduced its formation strength significantly. This fracturing can lead to severe losses, which in itself can cause an underbalance (and thus unstable) situation in the underlying shale. Additionally since the well had been sidetracked 15 years previously, it had not been possible to kill it successfully. Therefore, preventing severe losses in the upper reservoir was identified as a major challenge.