Abstract

Access to previously unattainable offshore drilling targets continues to expand through advancements in Managed Pressure Drilling (MPD) and Dynamic Annular Pressure Control (DAPC) technologies since their first application on the Mars TLP in 2005. Shell Exploration & Production Company successfully executed a second MPD operation, eliminating lost circulation and hole instability risks by utilizing a DAPC system on the Auger TLP.

Redevelopment drilling in maturing deepwater fields is challenged by high circulating density (ECD) and depletion induced fracture gradient (FG) reduction for intervals that still require original mud weights (MW) for borehole stability. The DAPC system provides automated control of surface applied annular backpressure to the wellbore to a specified bottom hole pressure (BHP) set point. This allowed drilling on the Auger TLP with a surface mud weight lower than required by conventional drilling, effectively reducing the ECD magnitude on the open hole.

The well design will be discussed, along with the equipment, methods, planning, preparation and training to successfully execute MPD offshore. Execution results and key learnings will be summarized.

Introduction

Shell's Auger Tension Leg Platform (TLP) is located in the Gulf of Mexico (GOM) in 2860 feet of water on Garden Banks block 426. The TLP began production in 1994 as the first deepwater platform in the GOM and has continuously produced from five main reservoirs across four outer continental shelf (OCS) blocks. Peak production was achieved in 1999–2000, and cumulative production has surpassed four hundred million barrels equivalent, which has yielded reservoir pressure depletion in excess of 5000 psi. The depletion has caused rock stress modification in both the sands and shale overburden, resulting in reduction of original fracture gradients and therefore tighter drilling margins.

Redevelopment drilling programs have been conducted on the Auger TLP since 1999 with limited success, with unmanageable lost circulation events identified as the root cause. The reduced facture gradient challenge is further compounded in redevelopment sidetracks as the casing and drill pipe geometry yield larger annulus friction pressures than original well drilling. Managed Pressure Drilling (MPD) has been identified as a critical technology to mitigate the challenges of the tight drilling margin environment.

The A-18 ST3 well was the first well in the 2006 redevelopment campaign. The objective was an up-dip target location in an undepleted reservoir fault block. The required sidetrack depth, however, was above known depleted reservoirs, thus presenting the risk of lost circulation if drilled with conventional mud weights.

The original well was batch set in 1992 prior to the TLP installation and later drilled to total depth (TD) from the TLP in 2000 as an exploration step-out well. The drilling of ST1 and ST2 was performed as part of the original TD due to wellbore positioning and a well control event in the objection section, resulting in stuck pipe. Eventually successful, the ST2 was drilled and cased across the objective targets with a 5–1/2" × 7" tapered production liner, then cased to surface with a 7" × 7–5/8" tapered production tieback.

Due to the existing casing configuration, the casing exit for ST3 was made via a whipstock through the dual casing geometry of 7" 38# production liner × 9–5/8" 43.5# drilling liner at 17600 ft measured depth (MD). The directional plan consisted of a 3900 ft interval and a 2-dimensional 'S' shaped profile starting at 20 degrees inclination, then building to a maximum of 55 degrees and dropping to a target inclination of 25 degrees through the objective reservoir. A 5–3/4" × 6–1/2" underreamed hole was drilled with rotary steerable and measurement & logging while drilling (MWD/LWD) drilling bottom hole assembly (BHA).

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