OTC-24324-MS

Geomechanical analysis and critically stressed fractures in Offshore Brazil M. Cruz, OGX; J. Oliveira, TEKTOS Consultoria; B. Silveira, Baker Hughes

Copyright 2013, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Brasil held in Rio de Janeiro, Brazil, 29–31 October 2013. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract

The relationship between in-situ stress and permeability of faults and fractures is widely recognized. However the original

paradigm that mode 1 fractures would be responsible for the performance of the reservoirs, contradict the hypothesis that

hydraulically active faults and fractures are those whose relationship between the normal and shear stress favors the rupture

under the current stress tensor (critically stressed fractures hypothesis). Also, the current stress tensor influences the well

stability and choice of more stable trajectories of deviated and horizontal wells, which ensures lower costs and safer drilling

operations.

In order to better understand the relationship between in-situ stress and critically stressed fractures, a geomechanical analysis

in wells located offshore Brazil was performed. The aim of this study was to determine the stress tensor, the well stability and

recognize critically stressed fractures.

From well data the stress tensor and fracture population were determined. After that, various conditions of stress were

simulated until the critically stressed fractures were achieved.

Introduction

Fractured reservoirs show a complex distribution of faults and fractures which reflects the progressive activity of several stress

fields along geological history. However, for the purposes of hydrocarbon production, the hydraulic conductivity of the

fractured medium is strongly influenced by the current stress field. Because of that, geomechanics characterization of in situ

stress is mandatory in fractured reservoirs studies.

The reservoir stimulation by hydraulic fracturing, the placement and well design, the permeability anisotropy in porous

reservoirs and seal breach by fault reactivation are other factors strongly affected by current stress field (Ameen 2003 Rajabi et

al 2010), but this analysis is beyond the scope of this work.

The current assumption is that active hydraulic conductive fractures are oriented parallel to the main stress axis. However,

evidences accumulated during the last years suggests that most of the fluid transport occurs through planes and fractures

properly oriented with the current stress field to fail in shear (Figure 1 - Critically Stressed Fractures, Barton et al 1995).

In fact, the spatial orientation of the critically stressed fracture planes correspond to only one of the two shear planes that

forms the conjugate pair in the active stress tensor. Although the production of hydrocarbons is not exclusively associated with

these fracture planes, it is estimated that they have a much higher production performance when compared to other fractured

intervals (see, for example, Chanchani et al 2003).

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Figure 1: Fractures in red have orientations which favors slip and hydraulic conductivity (Critically Stressed Fractures).

Because fracture permeability is strongly influenced by the current stress tensor, it is necessary prior determination of in situ

stress in order to identify the population of critically stressed fractures. The determination of in situ stress requires the

estimation of magnitude and spatial orientation of the three principal stress axis (Figure 2 - Sv, SHmáx and Shmin) based on

data from image profiles, well logs, leak-off tests, hydraulic fracturing, amongst others.

Figure 2: Principal axis of stress in sedimentary basins (Geomechanics).

Once determined the tensor, it is possible to calculate the shear stress/normal stress ratio for each of the fracture surfaces

interpreted in the image profiles and, thus, determine the population of fractures whose spatial orientation favors a better

hydraulic performance based on theoretical assumptions stated above. Then, well trajectories can be optimized to intersect the

maximum amount of permeable fractures (Figure 3).

Figure 3: Populations of conductive and non-conductive fractures properly mapped and ideal locations of wells. The simplistic alternative of locate a well

crossing the largest number of fractures result in a dry well (red color). Modified from Zoback, 2010.

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The essence of the applied method with critically stressed fractures can be seen, for example, in Barton (1995) and Zoback

(2010). Rogers (2003) presents a case study where the Critical Theory Stress was applied in a well in the UK.

Geological Settings In order to better understand the relationship between in-situ stress and critically stressed fractures, a geomechanical analysis

in wells located offshore Brazil was performed. The aim of this study was to determine the stress tensor, the well stability and

recognize critically stressed fractures.

The analized interval is characterized by two fault systems: one NE-SW, parallel to the opening of the basin, and the other in

the perpendicular direction (NW-SE). Geomechanical model

Geomechanical model, including pore pressure estimation, rock mechanical properties, in situ stress orientations and

magnitudes and fractures geometry were created. The objective is to understand how the fractures were contributing to fluid

flow and how futures wells could be planned in order to increase the production.

The geomechanical model begins by defining the principal stress tensor. The principal stress tensor resolves the in situ stresses

into three mutually perpendicular vectors, S1, S2 and S3, which are the maximum, intermediate, and minimum stresses,

respectively. The stresses measured in sedimentary basins can typically be defined by a vertical stress (Sv) and two mutually

perpendicular horizontal stresses (SHmax, Shmin). Depending on the stress regime the values of Sv, Shmin, and SHmax can

be S1, S2, or S3 (Figure 4).

The pore pressure acts against the principal stresses and must be defined to fully describe the stresses. Rock strength and other

rock properties must also be known to fully define the geomechanical model.

Figure 4: Sv, SHmáx and Shmin and the principal axis of stress in each regime tensional (Zoback, 2010)

Data Set The Data set for 3 wells comprises wireline logs (Gamma Ray , Resistivity, Density and Sonic), drilling reports, mud weights,

casing depths, formation tops, well surveys, pore pressure measurements and interpreted images. (Previous studies with 19

wells were considered to understand the geomechanical model).

No drilling occurrencies were observed that could indicate geomechanical problems. Hydrostatic pore pressure was obtained

from formation tests.

The insufficient information of leak off tests and breakouts cause some uncertainties to constrain UCS, SHmax and Shmin.

Image Logs Failure Analysis

A stress concentration is set up around the wellbore when the rock that previously supported the far-field stresses is removed.

The mud weight in the well must support the stresses previously supported by the removed material. The stresses are

concentrated at the wellbore wall, with the stresses becoming less compressive in the orientation of the maximum horizontal

stress and more compressive in the orientation of the minimum horizontal stress. If the stresses in the orientation of SHmax

exceed the tensile strength of the rock then a small tensile crack will form. If the stresses in the orientation of Shmin exceed

the compressive strength of the rock then a compressive failure or “breakout” will form (Figure 5).

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Figure 5: Breakouts and SHmáx direction.

Wireline log data were used in order to identify and characterize welbore failure. The ability to observe failure is dependent on

image data quality and type of the imaged rock. Few breakouts were interpreted with high uncertainty, but they were used to

estimate the SHmax.

The azimuth and Magnitude of SHmáx is NW-SE based on limited wellbore breakouts from the image logs. Figure 6 show some

interpreted breakouts.

Figure 6: Interpreted breakout. The orientation of the breakouts give us an Azimut of Shmax of NW-SE.

Pore Pressure and Overburden Analysis

Combined curve from acoustic, resistivity and density were used to predict pore pressure. The pore pressure is highly

correlated to the wellbore collapse and the fracture gradient, so the better this information is, the better the geomechanical

model will predict borehole collapse conditions.

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Vertical stress can be calculated by integrating density logs. It is very important to get at least one density log to surface or as

shallow as possible. A power law relationship can then be fit to the surface to fill in the missing data.

Figure 7: Pore pressure and overburden profile for one of the wells.

Least Principal Stress Model

There are several methods to calculate the least horizontal stress: Leak off tests and extended leak off tests, minifrac tests,

step rate tests, PWD analysis of ballooning incidents, Mud weights (ideally PWD data) during lost circulation incidents (if

losses are not due to fault zone). Infact formation integrity tests (FIT’s) typically do not provide any useful stress information –

not even a lower bound for S3.

In this data set there was little information about geomechanical properties. Because of this, in order to find a robust value,

tests from different areas and their effective stress ratio were used in the model.

Rock Mechanical Properties

The comprehension of the rock mechanical properties is an important part of building a geomechanical model. The mechanical

behavior of the rock is dependent of mechanical properties as unconfined strength, friction coefficient, Poisson’s ration, Biot’s

coefficient, etc. Ideally laboratory measurements are the parameters used to calibrate the correlations in the geomechanical

analysis. Due to high costs of acquiring these cores tests, they are rarely conducted. So, these properties are derived largely

from acoustic, porosity and gamma ray data.

No mechanical properties were available in the analized area, but data from another place were considered in order to verify

the magnitude of these properties.

The following relationships were used to calculate the rock mechanical properties:

• Shale UCS – Vp cubed relationship

•

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• 72.5 x pow(Vp,3)

• Sandstone UCS – McNally

• ( )

• Limestone UCS – modified porosity relationship (10000 x exp(-3.7 x PHI)) calibrated from the previous

model update (2008)

• ( )

• Internal friction relationship – Lal Vp for shale; Chang & Zoback for sandstone and limestone

• [( )

]

• Poisson’s ratio – dynamic Poisson’s ratio

Results

Based on the calculated strees tensor, the following figures show the results obtained. Fractures appear with their azimuth and

dip value, with critically stressed fractures marked in red.

Figure 8: Well a. Fractures distribution and stereonet of well stability. With the parameters used, no population of fractures was stressed.

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Figure 9: Well b. Fractures distribution and stereonet of well stability.With the parameters used, two fracture planes were stressed.

Figure 10: Well c. Fractures distribution and stereonet of well stability.With the parameters used, one population of fractures were stressed; the conjugate pair

is in normal stress regime.

According to diagrams previously showed, the well c (Figure 10), deserves closer analysis. Even in the face of pervasive

fracturing, the stressing of the fractures, such as in the well b, was only made possible by the adoption of a friction coefficient

very low (0.27), if taken into account the values typically used for calculations of this nature, that fall between 0.6 and 1.0.

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Conclusions

The study indicates that the stress tensor is under a normal stress regime. With the calculated stress values, the modeling stress

fitting of the fractures is only possible by using a coefficient of friction much lower than normally used for such calculations.

This fact suggests that the fractures do not play a relevant role in the dynamics of the analized rocks.

Despite the need of more detailed studies, throughout the assumptions of rigid deformation processes, it is unlikely that the

spatial attitude of fault planes has not been addressed by the modeling performed in fractures.

Acknowledgements

The authors would like to express their gratitude to colleagues from OGX, Paulo Ernesto and Dayse Daltro by criticism,

suggestions and incentives. We also thank the petrophysical Albano Bastos for fruitful discussions which preceded the final

version of this paper.

Bibliografia

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Barton, C.A., Zoback, M.D. and Moos, D. 1995. Fluid flow along potentially active faults in crystalline rock. Geology, 23, p.683-686.

Chanchani, S.K., Zoback, M.D. and Barton, C. 2003. A case study of hydrocarbon transport along active faults and production-related stress

changes in the Monterey Formation, California. In: Fracture and In-situ stress characterization of hydrocarbon reservoirs. Geological Society Spec Publ 209, 17-26.

Rajabi M., Sherkati S., Bohloli B. and Tingay M., 2010. Subsurface fracture analysis and determination of in-situ stress direction using FMI logs: An example from the Santonian carbonates (Ilam Formation) in the Abadan Plain, Iran. Tectonophysics 492, p.192-200.

Rogers, S.F. 2003. Critical stress-related permeability in fractured rocks. In: Fracture and In-situ stress characterization of hydrocarbon reservoirs. Geological Society Spec Publ 209, 7-16.

Zoback, M.D. 2010. Reservoir Geomechanics: Cambridge. Cambridge University Press, 449 p.