New Automated Control System Manages Pressure and Return Flow While Drilling and Cementing Casing in Depleted Onshore Field

Abstract

Abstract Development efforts by Shell in South Texas have focused on technology solutions to eliminate the often encountered troubles drilling through significantly depleted sands to get to over pressured reservoirs below. The limits imposed by those conflicting conditions create narrow windows in which the difference between equivalent circulating density (ECD) and static bottom hole pressure (BHP) can be the difference between lost circulation and influx. Liner drilling with statically underbalance (SUB) mud is one solution Shell uses in low permeability reservoirs to eliminate lost circulation in part because it eliminates swab and surge effects and heavy trip margins. But by itself that solution doesn't work everywhere. In the McAllen and Pharr fields the amount by which the risk of losses can be reduced with liner drilling is limited because the sands can be more permeable and more likely to flow with SUB mud. For that reason Shell turned to automated managed pressure drilling (MPD) as a solution to drill more permeable reservoirs with SUB mud without influx. For the past two years Shell has used those complementary solutions in the McAllen-Pharr fields to improve drilling efficiency and reduce costs with mud statically less than pore pressure and constant bottom hole pressure (BHP). Recently, Shell drilled the Bales #7 well in the McAllen Field Wide Unit using a new scaled-down automated MPD system. The lower 700 feet of the 6½ hole was drilled in with 3½ production tubing with 15.7 ppg static mud into a target sand with an expected pore pressure of 15.8 ppg. In that interval the ECD was 16.2 ppg and the fracture gradient was 16.5 ppg which was the narrowest window that Shell has drilled in the McAllen-Pharr area to date. During casing drilling operations there was a steady flow of drill gas that varied between 1100 and 1400 units. Even with the drill gas the MPD system managed the BHP at a 16.2 ppg set point, +/− 0.18 ppg, without the use of an automated back pressure pump. That allowed Shell to avoid losses and the cost of a 5½ contingency liner drilling operation. In addition, and in the first of its kind application, Shell used the system to manage the BHP while cementing the drilled-in production tubing. With its smaller footprint, more efficient automated control, and proven ability to manage constant BHP this new MPD system can provide onshore and offshore operators a solution to improve drilling and cementing operations in mature depleted fields.