Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data
- Bikash K. Sinha (Schlumberger) | Tom R. Bratton (Schlumberger) | Jesse V. Cryer (Schlumberger) | Steve Nieting (Schlumberger) | Gustavo A. Ugueto (Shell) | Andrey Bakulin (Shell Intl. E&P Inc.) | Matt R. Hauser (Shell E&P Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2008
- Document Type
- Journal Paper
- 478 - 486
- 2008. Society of Petroleum Engineers
- 2.2.2 Perforating, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.11 Drilling Fluids and Materials, 5.6.1 Open hole/cased hole log analysis, 1.2.2 Geomechanics, 5.8.7 Carbonate Reservoir, 5.5.11 Formation Testing (e.g., Wireline, LWD), 2.4.5 Gravel pack design & evaluation, 1.6.6 Directional Drilling, 2.4.3 Sand/Solids Control, 1.7.6 Wellbore Pressure Management, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 3 Production and Well Operations, 5.3.4 Integration of geomechanics in models, 1.6 Drilling Operations, 2 Well Completion
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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 (SH max) and minimum (Sh min) 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.
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 (SH max and Sh min) 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).
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