Summary
Highly depleted reservoirs exhibit sharply lower pore pressures and
horizontal stress magnitudes than does the overlying shaly formation. Drilling
through such depleted reservoirs can cause severe fluid loss and
drilling-induced wellbore instability. Accurate and reliable estimates of
horizontal stresses can provide an early warning of impending drilling problems
that may be mitigated by appropriate drilling fluid design and drilling
practices. We have developed a new multifrequency inversion algorithm for the
estimation of maximum and minimum horizontal stress magnitudes by use of
cross-dipole dispersions. Borehole sonic data for the case study presented in
this paper was acquired by a cross-dipole sonic tool in a deepwater well,
offshore Louisiana in the Gulf of Mexico (GOM). The logged interval spans 1,000
ft below the casing shoe. In addition, the Modular Dynamic Tester (MDT)
(©Schlumberger) minifrac tests were performed at three depths in shale, thus
yielding two minimum horizontal stress magnitudes. The borehole sonic data were
suitable for the inversion of cross-dipole dispersions at three depths in
shale, as well as at a depth in a highly depleted sand reservoir. There was one
depth in shale above the depleted sand where we could estimate the minimum
horizontal stress magnitude by use of both the MDT minifrac tests and inversion
of borehole sonic data. The results of the two techniques are consistent,
providing encouragement for further validation of the multifrequency inversion
of cross-dipole dispersions to estimate horizontal stresses. Even though the
overburden stress is expected to increase with depth, both the maximum
(SHmax) and minimum (Shmin) horizontal stresses obtained from the inversion of borehole
sonic data are significantly smaller in the depleted sand than in the
overburden shale. However, both the horizontal stress magnitudes increase again
in the shale below the depleted sand. Such rapid variations in horizontal
stress magnitudes cause large fluctuations in the safe mud-weight window. This
challenge in drilling through the depleted sand was successfully handled by
using special drilling fluid to mitigate seepage losses and the differential
sticking in the depleted sand and overlying shale. We have also performed
dipole radial profiling (DRP) of formation shear slownesses using the measured
cross-dipole dispersions at three depths in shale and one in highly depleted
sand. Analysis of radial profiles in the two orthogonal directions indicates
plastic yielding or stiffening of rock in the near-wellbore region. While
plastic yielding increases the shear slowness, stiffening would reduce the
shear slowness.
Introduction
Formation stresses play an important role in geophysical prospecting and
development of oil and gas reservoirs. Both the direction and magnitude of
these stresses are required in (a) planning for borehole stability during
directional drilling, (b) hydraulic fracturing for enhanced production, and (c)
selective perforation for prevention of sanding during production. Wellbores
drilled through base salt in the GOM are subject to increased risks of hole
closure that might be attributed to the complex and rapidly varying formation
stresses. In addition, drilling through highly pressure-depleted reservoirs
raises considerable risks of excessive mud loss, internal blowout, and
differential sticking (van Oort et al. 2003). Drilling through such depleted
sands was accomplished in the Ursa field in the GOM using water-based mud with
monomer and resin materials that exhibit larger fracture propagation pressure
than do those of oil-based mud (however, the fracture opening pressures are
similar for both the water-based and oil-based mud. )
The formation stress state is characterized by the magnitude and direction
of three principal stresses. Fig. 1 shows a schematic diagram of a vertical
borehole in a formation subjected to the three principal stresses. Generally,
the overburden stress (SV ) is reliably obtained by
integrating the formation mass density from the surface to the depth of
interest. Consequently, estimating the other two principal stresses
(SHmax and Shmin)
in the horizontal plane is the remaining task necessary to fully characterize
the formation stress state.
Existing techniques for the estimation of horizontal stress magnitudes based
on correlations with dynamic Poisson’s ratio may not reliably yield the rapid
variations in horizontal stresses in different stratigraphic layers.
The MDT in dual-packer stress testing mode yields the minimum in-situ stress
magnitude (Desroches and Kurkjian 1999). Currently, the maximum horizontal
stress must be determined from damage mechanics constraints based on borehole
breakouts (Vernik and Zoback 1992). Estimating the maximum horizontal stress
magnitude remains a challenge in the industry.
Near-wellbore alteration can be caused by several sources, such as borehole
stress concentrations, drilling mud pressure, plastic yielding of the rock
prior to breakouts, shale swelling, drilling-induced fractures, and invasion of
monomer and resin materials in synthetic drilling muds used to strengthen weak
formations (van Oort et al. 2003; Gnirk 1972; Blakeman 1982; Plona et al.
2002). Estimation of the magnitude and radial extent of mechanical alteration
helps in creating an optimal design of perforation tunnel length for the
improved flow rate in the presence of near-wellbore permeability
impairment.
This paper presents a summary of results for the minimum horizontal stress
obtained from the microhydraulic fracturing technique performed with the
dual-packer module of the MDT tool. Next, we describe results from the analysis
of cross-dipole sonic data from a post-drill logging program for the well to
estimate the formation stress magnitudes and radial extent of near-wellbore
alteration. This well was successfully drilled through a highly depleted sand
reservoir by use of a special synthetic mud that allowed substantially less
fluid loss than typical muds. In the sands, we infer the radial depth of
invasion of the monomer and resin components of the mud from the radial profile
of shear slowness away from the borehole surface. We also compare results for
the minimum horizontal stress magnitudes obtained from the borehole sonic data
with magnitudes estimated from the mini-frac tests performed with the MDT
dual-packer module in the shales.
Radial profiles of shear slownesses together with annular pressure history
can also be used to estimate in-situ unconfined compressive strength (UCS) of
the rock (Bratton et al. 2004).
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
20 July 2005
- Meeting paper published:
9 October 2005
- Revised manuscript received:
19 June 2007
- Manuscript approved:
13 August 2007
- Version of record:
20 June 2008
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