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In this paper, we review a suite of techniques for determination of in situ stress orientation and magnitude in deep wells and boreholes. As these techniques can be utilized in both vertical and highly deviated wells, they have had extensive application in the petroleum industry where knowledge of stress orientation and magnitude at depth is important for addressing a wide range of problems. The techniques we have developed for estimation of the maximum horizontal principal stress, SHmax; make extensive use of observations of non-catastrophic failures of the wellbore wall—both compressive failures (breakouts) and tensile failures (drillinginduced tensile fractures) as well as the stress perturbations associated with slip on faults cutting through the wellbore. The widespread use of wellbore imaging in the petroleum industry has been a critical development that makes utilization of these techniques possible. In addition to reviewing the theoretical basis for these techniques, we present case studies derived from oil and gas fields in different parts of the world. These case studies document the facts that the techniques described here yield (i) consistent stress orientations and magnitudes over appreciable depth ranges within and between wells in a given field (thus indicating that the techniques are independent of formation properties), (ii) stress magnitudes that are consistent with absolute and relative stress magnitudes predicted by Anderson and Coulomb faulting theories, (iii) stress orientations and relative magnitudes that are consistent with regional stress indicators and tectonics observed with other techniques at much larger scales and (iv) sufficiently wellconstrained estimates of the full stress tensor that are useful in application to engineering problems such as wellbore stability. r 2003 Elsevier Ltd. All rights reserved.

A comprehensive geomechanical approach to wellbore stability requires knowledge of rock strength, pore pressure and the magnitude and orientation of the three principal stresses. These parameters are often uncertain, making confidence in deterministic predictions of the risks associated with instabilities during drilling and production difficult to assess. This paper demonstrates the use of Quantitative Risk Assessment (QRA) to formally account for the uncertainty in each input parameter to assess the probability of achieving a desired degree of wellbore stability at a given mud weight. We also utilize QRA to assess how the uncertainty in each parameter affects the mud weight calculated to maintain stability. In one case study, we illustrate how this approach allows us to compute optimal mud weight windows and casing set points at a deep-water site. In another case study, we demonstrate how to assess the feasibility of underbalanced drilling and open-hole completion of horizontal wells utilizing a comprehensive stability analysis that includes application of QRA.

Summary In this paper, we address the theoretical possibility of drilling with mud weights in excess of the least principal stress for cases of particularly high pore pressure or severe wellbore instability. Because lost circulation caused by hydraulic fracturing is to be avoided, we consider three critical wellbore pressures, pfrac, plink, and pgrow. Tensile fractures initiate at the wellbore wall at pfrac, link up to form large axial fractures that are subparallel to the wellbore axis at plink, and propagate away from the wellbore at pgrow. It is obvious that lost circulation cannot occur if the wellbore pressure during drilling is below pfrac. However, even if pfrac is exceeded and tensile fractures are initiated at the wellbore wall, fracture propagation (and, hence, lost circulation) will be limited as long as the wellbore pressure is below plink. Finally, if the wellbore pressure is greater than plink, the fractures will not grow away from the wellbore (and significant lost circulation will not occur) if the wellbore pressure is below pgrow, which must exceed (if only slightly) the least principal stress. In general, our modeling shows that pfrac and plink can be maximized by drilling the wellbore in an optimally stable orientation, and pgrow can be maximized with noninvading drilling muds that prevent fluid pressure from reaching the fracture tip. We apply the model that uses in-situ stress data collected in real fields, such as the South Eugene Island field in the Gulf of Mexico and the Visund field in the northern North Sea.

In this paper we investigate the occurrence of compressive and tensile failures of arbitrarily inclined well bores under a wide variety of stress conditions. The principal assumptions in this analysis are that the rock is isotropic and that it deforms elastically to the point of failure. As has been shown by previous investigators, for a given stress state and well bore orientation, it is straightforward to predict the orientation of the failures around the well bore as well as whether failure is likely to occur depending on such parameters as rock strength and borehole fluid pressure. However, as the stress state is almost never known in situ, we demonstrate how observations of compressive and tensile wall failures in inclined holes can be used to constrain in situ stress orientations and magnitudes if there are independent data on the magnitude of the least principal stress from either leak-off or microfrac tests and on the formation pore pressure. We further demonstrate how once the stress state is determined, it is possible to assess both an upper bound on the effective in situ rock strength and the degree to which increasing the borehole fluid pressure (or mud weight) can reduce the likelihood of borehole failure. Through application of this methodology to an inclined well bore in an area of complex faulting in the Gulf of Mexico, we illustrate how it is possible to utilize observations of borehole failures to determine the magnitude and orientation of the stress tensor in areas such as offshore sedimentary basins where drilling inclined well bores is quite common.

Summary We present a relatively simple technique to constrain in-situ stress and effective rock strength from observations of wellbore failure in inclined wells. Application of this technique in the Global Basins Research Network (GBRN)/DOE "Pathfinder" well demonstrated that (1) the azimuth of Shmin is N42 E, perpendicular to a major growth fault penetrated by the well; (2) the magnitude of SHmax is relatively close to the vertical stress; and (3) the effective in-situ compressive rock strength is 3,500 to 4,000 psi. We show that once we have estimated in-situ stress and rock strength, it is possible to compute the mud pressure required to inhibit failure for wells of any azimuth and inclination. Finally, we show how it is possible to estimate the magnitudes of both Shmin and SHmax in cases where independent knowledge of stress orientation is available (for example, from wellbore breakouts in nearby vertical boreholes). Introduction Improved knowledge of in-situ stress and effective rock strength in hydrocarbon reservoirs is important in a number of problems ranging from borehole stability and sand production to hydrocarbon migration and hydraulic fracturing. We have conducted a comprehensive series of calculations of the occurrence of compressive failures and drilling-induced, tensile wall failures in arbitrarily inclined boreholes1 and showed how such observations can be used to determine stress orientation and magnitude, effective rock strength and the optimal mud weight for borehole stability. In this paper, we present application of this theory to observations of compressive wellbore failures in the GBRN/DOE Pathfinder well, an inclined well drilled in conjunction with Pennzoil Co. in Block 330 of the South Eugene Island field of the Gulf of Mexico. Stress-induced compressive failures of wellbores are commonly known as stress-induced wellbore breakouts and can be observed with either four-arm, magnetically oriented calipers (such as with dipmeter logs) or borehole televiewers. Drilling-induced, tensile wall failures in inclined boreholes also can be used to constrain in-situ stress magnitudes. In contrast to drilling-induced hydraulic fractures that propagate away from the borehole and are associated with lost circulation, tensile wall failures occur only in the wellbore wall and are detected only through careful inspection of the borehole wall with Formation MicroScanner/MicroImager logs (FMS/FMI). In this study, we focus on stress-induced wellbore breakouts as they are commonly observed in oil and gas wells, and numerous studies have shown that breakouts in near-vertical wells accurately reflect in-situ stress orientations when care is taken to distinguish stress-induced wellbore breakouts from other processes that change the cross-sectional shape of a borehole.4 In this analysis, we use the following observations in inclined wellbores.The orientation at which breakouts occur around the wellbore.Leakoff data to constrain the magnitude of the least principal horizontal stress, Shmin, in the case study presented.Estimates of the vertical stress and pore pressure. These observations are used to constrain (a) the values of the unknown components of the in-situ stress tensor (in the case study presented, these are the orientation of the horizontal principal stresses and the magnitude of SHmax), (b) the maximum effective strength of the rock in situ, and (c) the mud weight necessary to inhibit failure. We illustrate this technique with some relatively simple diagrams that show how breakout orientations depend on the in-situ stress state and borehole orientation and how the tendency for failure further depends on rock strength, pore pressure, and mud weight. We also demonstrate that in cases where the orientation of the horizontal principal stress is already known (for example, from breakouts in vertical wells), the magnitudes of both Shmin and SHmax can be estimated. Mastin demonstrated that breakouts in inclined holes drilled at different azimuths are expected to form at various angles around a wellbore depending on both the stress state and exact hole orientation. In fact, for this very reason, observations of breakouts in inclined holes are not normally used to determine in-situ stress orientation. Qian and Pedersen and Aadnoy proposed complex nonlinear inversions of failures in multiple inclined boreholes to constrain the in-situ stress tensor. As illustrated later, the technique we propose can yield useful constraints on the stress field from observations in a single borehole. In addition, it does not depend on detailed knowledge of formation properties and basically assumes only that the formation behaves elastically up to the point of failure. Peska and Zoback described the mathematical basis for the technique in detail. In summary, to compute the likelihood of compressive failure around the wellbore, we need to estimate the maximum effective stress in the plane tangential to the borehole, stmax, (1) and the normal stress on the borehole, (2) In Eqs. 1 and 2, the stress state in a borehole coordinate system is given by (3a) (3b) (3c) where z is parallel to the borehole axis; r is radial distance; is the angle around the borehole wall measured from the bottom of the hole; is Poisson's ratio; and p is the difference between the borehole fluid pressure and the pore pressure in the rock, pp.15 In Eqs. 1 through 3, the effective stresses, ij, are given by (4) where Sij is a component of the "total" stress tensor defined in a local borehole coordinate system derived from the far-field stress state through a series of coordinate transformations and ij is the Kronecker delta. Eugene Island 330 Field and the Pathfinder Well The Pathfinder well is an extension (from 7,300 to 8,075 ft) of Production Well A-20ST in Eugene Island Block 330, offshore Louisiana. It was drilled in 1993 as part of a joint project between GBRN, the DOE, and private oil industry with the one objective of testing the hypothesis that an active growth fault can be conduit for oil and gas migrating to the reservoir.

We have developed a new analytical model for underbalanced drilling (UBD) that takes into account that rocks have scale dependent strengths, that the full stress concentration is not developed at a given depth in a well until sometime after the drill bit has passed, and that fluid flow into the advancing wellbore leads to a zone of locally lower pore pressure surrounding the well that extends beneath the drill bit. The model predicts regions within which compressive shear failure will occur and also provides predictions of where spalling (tensile failure) is a possibility. The results provide a more realistic and less conservative prediction of wellbore risk than models developed to study the stability of overbalanced wells. This new model can be applied to predict whether underbalanced operations are possible in a given well, and also the severity of wellbore instability as a function of underbalance. In addition, the model allows constraints to be placed on the in situ stress field (magnitudes and orientations) based on observations of wellbore failure in wells which have been drilled underbalanced. Wells designed utilizing model predictions were drilled without incident, and the model also provided reasonable predictions of the state of stress.

Whilst the step-out lengths of proposed ERD wells are becoming more and more challenging, wellbore stability assurance technologies - both in the pre-planning and execution phases - are developing at an equal pace. In this paper we describe several new developments in theoretical understanding and predictive capability of rock failure surrounding wells drilled at high-angle to bedding that are required to solve the problems encountered in these challenging environments. Rig-site processes for the integration of this new understanding with real-time diagnostic measurement and monitoring provide the means to deliver borehole stability assurance for ERD wells drilled in the most challenging environments.

Drilling problems frequently result from severe mechanical failure of the wellbore wall and thus depend on the interplay between the magnitude and orientation of in situ stresses, rock strength, mud weight, and the orientation of the wellbore. Utilizing a new suite of software tools developed to study wellbore stability in a wide variety of geologic environments, we can accurately predict optimally-stable wellbore trajectories from knowledge of the stress tensor. The analysis is a two step process – first, we determine stress from observations of failure in existing wells. We can then apply this knowledge to predict the stability of proposed wells both while drilling and later during production. We illustrate this type of approach using three case studies. First, we combine observations of failure in a vertical well with rock strength measurements to demonstrate the feasibility of horizontal drilling in poorly consolidated reservoir sands. Next, we analyze the stability during production of a series of multilaterals drilled from a single inclined parent well. Finally, we show that wellbore stability can be controlled by the orientation of a well with respect to bedding, and illustrate a method to optimize the trajectory of wells to account for this effect.

To minimise wellbore failures in unstable environments, knowledge of the complete stress tensor is crucial to designing optimally-stable borehole trajectories, selecting suitable mud weights, and determining appropriate casing points. Understanding how the in situ stress field interacts with the drilling and production of a well enables one to design for maximum stability and to facilitate intersecting the greatest population of hydraulically-conductive fractures for efficient production. Knowledge of the in situ stress field is also important to reduce uncertainties in sand production prediction to allow more aggressive completion designs and production schedules.A new interactive software system, Stress and Failure of Inclined Boreholes (SFIB) (Peska and Zoback, 1995a) is used to demonstrate how observations of drilling-induced compressive and tensile wellbore failures from acoustic and electrical images in vertical and inclined boreholes can be integrated with routinely-collected drilling data (leak-off and drill stem tests) to construct a well-constrained stress tensor. These techniques can also exploit wellbore image data to constrain in situ rock strength in vertical and inclined wells. This paper illustrates how to apply this knowledge to limit wellbore instability, design optimally stable wellbores, develop constraints that help mitigate problems associated with sand production, and optimise productivity of fractured reservoirs.In addition to mapping drilling-induced wellbore features, image data can also be used to determine the distribution, orientation, and apparent aperture of natural fractures and fault systems. With knowledge of the orientations and magnitudes of the in situ stresses it is possible to identify the subset of fractures that are likely to be hydraulically conductive.Examples of recent applications in the North Sea, Gulf of Mexico, California, and Puerto Rico illustrating how this integrated approach can be used in a variety of tectonic settings.

Understanding the interaction between rock strength, in-situ stress, and engineering practice allows one to minimize wellbore failures by designing optimally-stable borehole trajectories and appropriate mud weights. We utilize an interactive software system, Stress and Failure of Inclined Boreholes (SFIB Peska, Zoback 1996), to illustrate how observations of drilling-induced compressive and tensile wellbore failures in vertical and inclined wellbores can be integrated with other routinely-available information to yield an estimate of the full stress tensor. We further illustrate how such information allows one to place bounds on in-situ effective rock strength. We consider a deviated well in the Visund oil field on the flanks of the Viking Graben along the Norwegian margin. A good quality electrical imaging log revealed drilling-induced tensile wall fractures in an orientation consistent with other observations of stress orientation in the region. Interpretation of these fractures indicates that the maximum horizontal stress is 72±6.5 MPa at an azimuth of 100°±10°. No breakouts were detectable in the well, indicating that the uniaxial compressive rock strength is greater than approximately 19 MPa. We demonstrate how we utilized this information to design an optimally-stable wellbore trajectory to minimize sand production.