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Oil/Gas Reservoirs

Drilling Time Reduction Through an Integrated Rock Mechanics Analysis

[+] Author and Article Information
Olav-Magnar Nes1

SINTEF Petroleum Research, S.P.Andersens vei 15B, NO-7031 Trondheim, Norwayolav-magnar.nes@sintef.no

Erling Fjær

SINTEF Petroleum Research, S.P.Andersens vei 15B, NO-7031 Trondheim, Norway

Johan Tronvoll2

SINTEF Petroleum Research, S.P.Andersens vei 15B, NO-7031 Trondheim, Norway

Tron G. Kristiansen

BP Norge AS, Godesetdalen 8, NO-4065 Stavanger, Norway

Per Horsrud

Statoil ASA, Arkitekt Ebbelsv.10, NO-7005 Trondheim, Norway

1

Corresponding author.

2

Current address: Weatherford Petroleum Consultants, Stiklestadveien 1, NO-7041 Trondheim, Norway.

J. Energy Resour. Technol 134(3), 032802 (Jun 21, 2012) (7 pages) doi:10.1115/1.4006866 History: Received August 27, 2007; Revised May 07, 2012; Published June 21, 2012; Online June 21, 2012

A working methodology to minimize wellbore stability problems has been established through the use of unique laboratory tests, an experimental database for fluid-rock interaction and physical properties of shales, and an integrated modeling approach utilizing different types of experimental and field data. The model simulations provide output accounting for a wide range of input parameters such as well inclination, mud chemistry, rock mechanical properties, field stresses and pressures, formation anisotropy, and shale mineralogy. The model output can subsequently be used to diagnose field drilling problems or to design drilling operations. As an example, data from a high pressure/high temperature (HP/HT) field offshore Mid-Norway as well as a field in the overpressured shales in the southern part of the Norwegian North Sea have been analyzed and compared.

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Copyright © 2012 by American Society of Mechanical Engineers
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References

Figures

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Figure 2

Cross-sectional image of a hollow cylinder sample after testing. Subsequent to testing, epoxy was injected to stabilize the sample, which was thereafter sliced to image the postfailure pattern around the wellbore.

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Figure 3

Estimated gradients for pore pressure and in situ stresses for an exploration well for an overpressured shale section in the southern part of the Norwegian North Sea. The present study focuses on Eocene shale at about 2051 mTVD RT.

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Figure 4

Axial strain during the main fluid exposure phase versus time for the Eocene shale section in the southern part of the Norwegian North Sea using various activity matched brines. The strain is given relative to the strain after normalization with 3.5 wt. % NaCl. The figure is taken from Nes [13].

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Figure 5

Lower stable mud weight limit versus time for the Eocene shale after drilling using an OBM at well inclinations of 0, 60, and 90 deg. Note that the in situ pore pressure is about 32 MPa, while the minimum horizontal stress is 37 MPa. In practice, the latter represents the maximum MW allowed.

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Figure 6

Lower stable mud weight limit versus time for the Eocene shale after drilling using OBM with various amounts of brine (OBW) corresponding to different fluid activities, a. The result with OBM is included for comparison. Note that the in situ pore pressure is about 32 MPa, while the minimum horizontal stress is 37 MPa. In practice, the latter represents the maximum MW allowed.

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Figure 7

Lower stable mud weight limit versus time for the Eocene shale after drilling using 20 wt. % KCl for well inclinations of 60 and 90 deg. For KCl, the well failed after 3–3.5 days due to tensile failure. The result with OBM is included for comparison. Note that the in situ pore pressure is about 32 MPa, while the minimum horizontal stress is 37 MPa. In practice, the latter represents the maximum MW allowed.

Grahic Jump Location
Figure 8

Estimated gradients for pore pressure and in situ stresses for an exploration well for an HP/HT field offshore Mid-Norway. The present study focuses on Lange shale at about 4480 mTVD RT.

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Figure 1

Overview of methodology for improved drilling efficiency in shales through integrated rock mechanics analysis

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