Successfully Managing Drilling-Fluid Losses in Multiple Highly Depleted Sands
Authors: Jones J.F. , Taylor G.D. , Barree R.D. 
Published: October 2008

Abstract
Successfully drilling through depleted sands to reach deeper targets often demands a delicate balancing act between maintaining mechanical stability in normally and over-pressured shales, while controlling fluid losses due to hydraulic fracturing. A host of considerations go into the planning process, including whether further production from the depleted zones is planned.
For a porous formation, it is generally accepted that hydraulic fracturing pressure is partially dependent upon formation pore pressure.1,2 However, the models commonly used to predict both fracture initiation and fracture propagation are often unable to predict the changes in hydraulic fracturing pressures due to depletion. The authors believe this is due more to the difficulty in predicting the data required to link pore pressure variations to stress, rather than a deficiency in the existing models. More significantly, these models typically assume no flow, and thus are not valid where there is significant fluid loss to the formation.
Due to the prohibitive cost of a new North Sea well, a stability analysis was performed to determine the feasibility of sidetracking from an existing well and then directionally drilling through two (2) highly depleted sand formations with a single hole section.
The case study presented compares the original mechanical stability and hydraulic fracturing estimates with the actual mud weights used to successfully complete this difficult drilling operation. Descriptions of hole instability and fluid losses are presented along with the drilling fluid parameters used to combat them. Methods used for estimating formation pore pressure, insitu stresses and formation rock properties are also described. In addition, possible explanations for the differences between the planned and actual stability estimates are explored, with future recommendations for similar operations.

Introduction
Marathon's Brae B platform is located in the North Sea, about one hundred and fifty (150) miles northeast of Aberdeen, Scotland in 326' of water (556' RKB to mudline). Gas and condensate production at Brae B is from two distinct sand formations: the North Brae reservoir starting at +- 12,400' TVD RKB, and the laminated Hugin sandstone layers (part of the Beinn formation) starting at +- 14,500' TVD RKB. Original formation pore pressure in the North Brae reservoir was approximately 6,500 psi (10.0 ppg), compared to original formation pore pressures in the Hugin sand layers of approximately 11,000 psi (14.6 ppg). At the time of this project in May of 2000, pore pressures in both of these reservoirs were depleted to roughly 6.5 ppg, or 4,200 psi and 4,900 psi respectively.
Nearby drilling with the Ocean Nomad in 1987 identified additional deeper reserves in what is called the Upper Sleipner reservoir. Two competing plans for drilling a well into the Upper Sleipner and then bringing production back to Brae B were reviewed. The first plan called for drilling a new well from the platform, while the second plan called for sidetracking from an existing North Brae well.