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Estimation of stress and geomechanical properties using 3D seismic data

David Gray,1* Paul Anderson,2 John Logel,3 Franck Delbecq,4 Darren Schmidt4 and Ron Schmid5

IntroductionIn 2008, the lead author was asked to derive a method that would increase the relevance of seismic data in shale plays. After a little research, it became apparent that geomechanical parameters derived from seismic data could be very important in shale plays. In most shale plays, and indeed in many other plays, stimulation of the reservoir by hydraulic fracturing is the primary mechanism used to increase rates of oil and gas returns to the surface. In ‘tight’ plays, such as shale gas, shale oil, and coal-bed methane, stimulation is required to make the wells eco-nomically viable. Rickman et al. (2008) described four geome-chanical considerations necessary for the design of a stimulation treatment. These are: brittleness, closure pressure, proppant size and volume, and the location of the initiation of the fracture. Seismic data allow for estimation of all of these values between existing wells except the proppant size and volume.

The term ‘brittle’ is defined by the Oxford Dictionary as ‘hard but liable to break easily’ and by Webster’s New World Dictionary as ‘easily broken or shattered’. Both of these defini-tions are appropriate for use in fracture stimulation, but are subjective. Although the term brittleness is used frequently in tight plays, an objective definition was missing until Rickman et al. (2008) defined a relationship expressing brittleness as a percentage and related it to Young’s modulus and Poisson’s ratio, which can both be derived from seismic data (e.g., Mallick, 1995 for Poisson’s ratio; Gray, 2005a for Young’s modulus). In this paper, a generalized form of the Rickman et al. (2008) percentage brittleness is estimated from Young’s modulus and Poisson’s ratio, which are both derived from inversion of seismic data.

Closure pressure or closure stress is defined in the Schlumberger Oilfield Glossary as ‘an analysis parameter used in hydraulic fracture design to indicate the pressure at which the fracture effectively closes without proppant in place’. In general it is empirically related to the minimum horizontal stress (e.g., Iverson, 1995). Expanding on Gray (2010b), a method for the estimation from seismic data of all three prin-cipal stresses, the vertical stress, v, the maximum horizontal stress, H, and the minimum horizontal stress, h, is introduced here.

Warpinski and Smith (1989) state that in-situ stresses are clearly the most important factor controlling hydraulic fracturing. Iverson (1995) shows that knowledge of shear anisotropy allows for a reformulation of the closure stress equation to account for non-equal horizontal stresses, which is generally the case in the earth’s crust, e.g., Bell et al. (1994). A simplification of Hooke’s law using linear slip theory (Schoenberg and Sayers, 1995) allows the estimation of principal stresses from wide-angle, wide-azimuth seismic data (Gray, 2011). The rock properties required in its imple-mentation are derived from wide-angle seismic data, e.g., Gray (2005a). The method is demonstrated by estimating the principal stresses and rock properties for the Second White Speckled Shale using seismic data acquired in central Alberta, Canada. The results show that only about one quarter of the Second White Speckled Shale in the survey area will fracture as a network, while most of the rest will fracture linearly and some areas will not fracture at all, which implies that this information can assist in the location of both wells and the optimal location to initiate fractures, which is the last of the

AbstractPrincipal stresses, that is vertical, maximum horizontal and minimum horizontal stresses, and elastic moduli related to rock brittleness, like Young’s modulus and Poisson’s ratio, can be estimated from wide-angle, wide-azimuth seismic data. This is established using a small 3D seismic survey over the Colorado shale gas play of Alberta, Canada. It is shown that this information can be used to optimize the placement and direction of horizontal wells and hydraulic fracture stimulations.

1 Nexen, 801 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 3P7.2 Apache Energy, Level 9, 100 St Georges Terrace, Perth W. Australia, 6000.3 Talisman Energy Norge, Verven 4, Sentrum, 4003 Stavanger, Norway.4 Hampson-Russell, Suite 510, 715 - 5th Avenue SW, Calgary, Alberta, Canada, T2P 2X6.5 CGGVeritas Canada Land Library, 715 - 5th Avenue S.W., #2200, Calgary, Alberta, Canada, T2P 5A2.* Corresponding author, E-mail: FDavid_Gray@nexeninc.com

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say, the area of a seismic survey. This is because the seismic response is calibrated to the well moduli through the process of amplitude versus offset (AVO) inversion. AVO inversion using wide angles can also be used to estimate density from which we can, in turn, calculate the vertical stress, v, through integra-tion. From v and the theory presented below, the minimum and maximum horizontal stresses, h and H, respectively, can be estimated from wide-angle, 3D seismic data.

If we assume that the rocks in-situ in the subsurface are constrained horizontally, i.e., the horizontal strain is zero in their natural state, and that the rocks are undergoing elastic deformation, then we can estimate the in-situ stress state of these rocks from elastic information (Iverson, 1995). In fact, estimates of the three principal stresses can be obtained from anisotropic elastic parameters (Iverson, 1995). Since elastic information is derivable from seismic data via AVO inversion, then the in-situ stress state can be estimated from anywhere where seismic waves have intersected the rocks at a wide (>40°) angle. Furthermore, the anisotropic stress equations of Iversen (1995) can be recast using parameters from linear slip theory (Schoenberg and Sayers, 1995), which can be derived from wide-angle, wide-azimuth, 3D seismic data (e.g., Lefeuvre et al., 1992; Varela et al., 2009), as shown here.

Using linear slip theory, Schoenberg and Sayers (1995) showed that Hooke’s Law can be simplified to:

(1)

where, i are the strains in the rock, j are the stresses in the rock, and S represents the compliance of the rock. Linear slip theory simplifies the compliance terms by separating it into two independent parts: Sb – the compliance of the background rock, and Sf – the compliance of the fractures and micro-fractures in the rock (Schoenberg and Sayers, 1995). The incorporation of the concept of micro-fractures is important because it allows for the relationship of fractures to stress (e.g., Crampin, 1994), which is required for this formulation relating linear slip theory to the in-situ principal stresses. It is assumed that the maximum horizontal stress is parallel to a single set of parallel vertical fractures or micro-cracks and the minimum horizontal stress is perpendicular to these fractures or micro-cracks (e.g., Schoenberg and Sayers, 1995). Expanding Equation (1) with linear slip theory leads to the following system of equations:

(2)

Rickman et al. (2008) geomechanical parameters derivable from seismic data for this shale gas reservoir.

In order to calibrate the closure stress to actual measure-ments taken in the field, an additional term, called the tectonic stress term, is often required to be added to the closure stress equation. Blanton and Olson (1999) state: ‘When independent measures of horizontal stress magnitudes are available from micro-fracs or extended leak-off tests, there is often a discrep-ancy between the log-derived and measured values, leading to the conclusion that the uniaxial strain assumption inherent to [their] Eq. 1 is inadequate. In order to improve the estimated stress values, an adjustment (calibration) is made by adding an additional stress term to [their] Eq. 1, thereby shifting the profile to match the measured values.’ In this paper, the strain-corrected method of Blanton and Olson (1999) is used to calibrate the clo-sure stress to known values. This method is adopted because it is expected that strain will change smoothly across bedding planes, whereas horizontal stress can change rapidly from formation to formation due to changes in elastic rock properties.

MethodSeismic waves travelling through the earth create small, short-term, strains in the rock that lie in the elastic regime of the rocks. Therefore, using the assumptions outlined below, we are able to calculate useful elastic moduli such as Young’s modulus and Poisson’s ratio (Rickman et al., 2008) or the LMR (Lamé’s modulus, shear modulus, and density) parameters of Goodway et al. (1997) (e.g., Gray, 2002). These moduli are described as dynamic because they are measured by relatively high-frequency measurements of velocities of elastic waves (Fjaer, 2009). These dynamic moduli measured by seismic and well logs occur in the high frequency range and with low strain amplitudes (Olsen et al., 2004).

When the rock is subject to long-term strain in geotechnical tests, such as in compressive failure tests used to judge the strength of rocks, static moduli are estimated from the slope of the stress-strain relationship (Fjaer, 2009). Therefore, the moduli related to hydraulic fracturing are most likely the static moduli, because hydraulic fracturing takes some time to build up the pressure required to fracture the rock. Olsen et al. (2004) suggested that the static modulus is a combination of the dynamic modulus and a non-elastic modulus related to permanent deformation. The correction of the dynamic moduli to equivalent static moduli is often done via such a method or by scaling (e.g., Fjaer, 2009). In addition, there can be a frequency-dependent effect related to the pore size, the squirt-flow mechanism described by Dvorkin and Nur (1993).

Seismic-derived dynamic moduli should indicate lateral changes in elastic moduli and brittleness, which is related to them (Rickman et al., 2008) between wells. There are many relationships between static and elastic moduli in the petro-physical literature, suggesting that the best way to calibrate them is by comparing local measurements of both. If such rela-tionships can be determined, then they can be used to constrain the extrapolation of static moduli away from wells within,

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by assuming that the vertical stress is set equal to the overbur-den stress and horizontal strains are set to zero. Thus, the only deformation allowed is uniaxial strain in the vertical direction.

When in-situ minimum horizontal stress measurements such as micro-fracture(1) tests or extended leak-off tests are available, there is often a discrepancy between the log-derived values (and therefore, seismic-derived values, since they are based on inversions to match log properties) and these meas-ured values, leading to the conclusion that the uniaxial strain assumption inherent is inadequate. In order to improve the estimated stress values, the stress is shifted by adding an additional ‘tectonic stress’ term to the equation to match the measured values (Blanton and Olson, 1999). Rather than adding a tectonic stress term, we use the tectonic strain method described by Blanton and Olsen (1999) to estimate a vertically variable shift in stress. The primary rationale for using tectonic strain rather than tectonic stress is that the horizontal strains are expected to be more continuous than the horizontal stress-es. This can be conceptualized through the realization, from Equations (5) and (6), that the horizontal stresses are functions of the continuous vertical stress multiplied by a function of the discontinuous parameters, E, v, and ZN. Then again, the fact that this calibration needs to be done implies that the rocks in question are undergoing horizontal strain, thereby revising our earlier assumption that the rocks are horizontally constrained. Nevertheless, this strain can be captured in the above equations by incorporating the tectonic strain term of Blanton and Olsen (1999). Thereafter, at the well, the horizontal stresses are calibrated to the well measurements and can then be used as estimates of inter-well stresses and, therefore, for well planning.

It turns out that a differential horizontal stress ratio (DHSR), i.e., the differential ratio of the maximum and minimum horizontal stresses as shown in Equation (7), can be calculated from seismic parameters derived from these equations alone, without any knowledge of the stress state of the reservoir, because v in Equations (1) and (2) cancels when calculating it:

(7)

DHSR is a very important parameter in determining how a res-ervoir is likely to fracture. In general, in hydraulic fracturing, it is preferable if it is small. When the DHSR is large, hydraulic fractures will tend to occur as non-intersecting planes parallel to the maximum horizontal stress, since fractures tend to be created parallel to it. In contrast, when the DHSR is small, fractures induced by hydraulic fracturing will tend to grow in a variety of directions and therefore intersect. This multi-directional fracture network tends to provide much better access to the hydrocarbons in the reservoir.

The knowledge of elastic parameters, such as Young’s modulus or the shear modulus, indicates which rocks are brit-tle and therefore likely to fail. Rickman et al. (2008) derived a means of estimating brittleness, B, from logs. Equation (8) is a generalized form of these equations. Brittleness is expressed

where E is Young’s modulus, v is Poisson’s ratio, and μ is the shear modulus. The parameters ZN and ZT represent the normal and tangential compliances, respectively.

Compliance is defined by the Merriam-Webster Dictionary as ‘the ability of an object to yield elastically when a force is applied’. In the case of linear slip theory, this definition should be applied to both the background material and the faces of fractures, i.e., it is the ability of the background material and/or a fracture in it to yield elastically when a force is applied. The normal strain component perpendicular to a fracture or a plane of weakness in the material is related to the material’s normal compliance, ZN. Shear strain components tangential to a fracture or a plane of weakness in the material are related to the material’s tangential compliance, ZT.

Making the assumption that one principal stress is vertical, so the other two are horizontal, Equation (2) may be used to write the horizontal strains as functions of these stresses. Given the assumption that the rocks, in-situ, are constrained horizontally, these horizontal strains are equal to zero:

(3)

and

(4)

Solving Equations (3) and (4) for the principal horizontal stresses yields the following equations:

(5)

and

(6)

All of the parameters in Equations (5) and (6) can be derived from seismic data (e.g., Mallick, 1995 for v; Gray, 2005a for E). Downton and Roure (2010) use modern wide-angle, 3D, seismic data to estimate ZN. The vertical stress is generally estimated by integrating logged density over depth and mul-tiplying by the acceleration due to gravity. As density can be estimated from seismic data (e.g., Van Koughnet et al., 2003), the vertical stress can also be estimated integrating the density estimated from seismic data. This means that the anisotropic in-situ stress state of the rock and its elastic moduli and brittle-ness can be estimated between wells through the use of modern 3D seismic data.

Since we know how to derive all these parameters from seismic data, we can also estimate all three principal stresses from seismic data. These stresses need to be calibrated to static stress measurements obtained from wells, and when this is done it is found that the horizontal stresses are frequently underestimated. Fortunately, the concept of tectonic stress has already been introduced in the engineering world to deal with this discrepancy. The formula for solving for stress is obtained

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Knowledge of the stress state prior to drilling can also be used to predict areas at risk for wellbore failure, thereby allowing for bypassing of these areas or preparation for the drilling problems likely to be encountered therein. For example, note that any of the formation breakdown pressures could be negative, then the formation will likely fracture solely due to the presence of the borehole. It is important to know this possibility before drilling because there is a risk of lost circulation in that borehole. This scenario does occur and is shown in the example below. The hoop stress can also be significantly higher than the closure stress. Therefore, it is important to be aware of this prior to attempting to initiate hydraulic fracture. Wide-angle, wide-azimuth, 3D conventional P-wave, or multi-component seismic data allow the estimation of these parameters before wells are drilled. For conventional seismic data, azimuthal inversion is used. For multi-component seismic data, birefrin-gence, registration, and inversion can be used. These parameters must be calibrated to known points of stress and elastic moduli within the reservoir. Then, using this additional knowledge, bet-ter well planning should be achievable in order to optimize well location, direction and location of hydraulic fractures. How this might be done is demonstrated in the following example.

ExampleA small, 9 km2, conventional P-wave, wide-azimuth, 3D seismic survey shot southeast of Red Deer, Alberta, Canada in the Western Canadian Sedimentary Basin (WCSB) is used to demonstrate the method. The target area is the Cretaceous Colorado Shale Group, highlighted by a dashed box in the figures, which sits above weak shales of the Joli Fou Formation and sandier Lower Cretaceous Mannville Formation. The Mannville Formation sits above an unconformity, below which the strata consist predominantly of carbonate rocks. It will be shown that the Second White Speckled Shale unit is the most brittle part of the Colorado Shale Group and will be the focus of this example. Figure 1 shows the DHSR as plates displayed over estimates of Young’s modulus for the entire 3D volume. The direction of the plates indicates the estimated direction of

H, and their size, the magnitude of DHSR (Figure 2). These show significant variations over this very small area, largely driven by h (Figures 3 and 4).

Estimates of the principal stresses are derived as described above and calibrated to stress estimates for the whole WCSB available from the WCSB Atlas (Bell et al., 1994) using the tectonic strain concept of Blanton and Olsen (1999). Local calibration is preferred, but no wells with stress estimates in the Colorado Shale Group are available in this area. For example, subsequent stress estimation projects performed by the authors have used information derived from local well-based closure stress estimates to calibrate the minimum horizontal stresses. Figures 3 and 4 show significant vertical and horizontal variations in h. Very low values are associated with Mannville Formation coals and the weak shales of the Joli Fou Formation. High values are associated with carbonates in the bottom of the figures below the unconformity.

as a percentage. These same equations can be applied to the inversion results because they are tied to these same logs:

(8a)

(8b)

and

(8c)

where BE is brittleness estimated from Young’s modulus, Bn is brittleness estimated from Poisson’s ratio and subscripts min and max denote minimum and maximum values.

In order to determine how these rocks will fracture under the stresses induced by hydraulic fracturing, knowledge of all these parameters is important. To fracture the rock, the pres-sure in the well must first overcome the hoop stress created in the rocks around the borehole. Then it must be greater than the far-field stresses away from the borehole in order to con-tinue its growth. The hoop stress and far-field stresses may be similar, but the possibility exists that they can be completely different from each other in both maximum stress direction and magnitude. In the example below, the hoop stress is about twice the far-field stress, so knowledge of both is critical. Such differences can have a significant impact on wellbore design.

The hoop stress is the additional tangential stress in the rock close to the borehole wall that is induced by the presence of the borehole. It can be estimated once the principal stresses are known. Since it has been shown above that the principal stresses can be estimated from seismic data, the hoop stress can also be estimated. The hoop stress, , at the borehole wall for three cases is considered here. For a vertical borehole, the minimum hoop stress is oriented parallel to h and is given by

(9)

For the top of a horizontal borehole oriented perpendicular to

H, with v > H,

(10)

For the side of a horizontal borehole oriented perpendicular to

H, with H > v,

(11)

The general case was given by Kirsch (1898). Following Lund (2000) and in the example below, it is assumed that the differ-ence, ΔP, between the fluid pressure in the borehole and the formation pore pressure is zero. It is necessary to overcome the hoop stress in order to initiate a fracture in the formation; therefore, these stresses can be considered as the formation breakdown pressure, PFB.

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estimated using the generalization of the approach of Rickman et al. (2008), described above, combining Young’s modulus and Poisson’s ratio as shown for these data in Figure 5. Furthermore, there are significant variations in the DHSR ranging from zero to over 100% (Figure 6). Both of these parameters have significant impact on whether and how the rock will fracture: higher values of brittleness indicate rocks that are more likely to fracture and lower values of the DHSR indicate areas where rocks will have a greater tendency to fracture into a network. Clearly, we want to find areas where both these properties

These variations are probably due to different litholo-gies being stressed differently as they drape over underlying pinnacle reefs of the Leduc Formation (Gray, 2005b), dif-ferential compaction stresses, stresses induced by underlying salt collapse, or stresses due to the presence of open fractures in this formation. The horizontal slice in Figure 1 shows 100% variations in Young’s modulus ranging from 12–24 MPa. Variations in Young’s modulus and Poisson’s ratio should be expected due to variations in lithology, porosity, fluid content, fractures and cement in any sedimentary rock. Brittleness is

Figure 1 Dynamic Young’s modulus from the 3D seismic volume shown in colour, with the scale numbered in units of GPa. Plates, indicated by the arrow, show the differential horizontal stress ratio (DHSR). The size of the plate is proportional to the magnitude of the DHSR and the direction of the plate shows the direction of the local maximum horizontal stress. The long axis of the survey is E-W and survey area is 9 km2.

Figure 2 Maximum horizontal stress, H , showing the target Colorado Shale and the Second White Speckled Shale (2WS) formation within it. The coloured stripes at the well locations are the vertical stress, v , for reference.

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zone in the middle of Figure 7, should be drilled first, which should move the best production forward, thereby increasing net present value.

It is significant that there are such large differences in the properties that are important for hydraulic fracturing over very short distances. Examination of the variations to the southwest of Well 14-13 in the north-central part of Figures 7 and 4 show a change from a very good area for hydraulic fracturing to a bad area over a distance of less than 200 m, much shorter than the length of most horizontal wells drilled in these plays. The results indicate that most of the Second White Speckled Shale will fracture with parallel fractures, implying that it will be very important to direct the horizontal wells intended to be fractured as nearly parallel to the average h direction as possible. Therefore, knowledge of the rapid variation in the direction of

occur in order to find the best areas for hydraulic fracturing. Young’s modulus is used as a proxy for brittleness throughout the remainder of this study.

This requirement for high brittleness and low DHSR suggests that a crossplot of these values should indicate areas that are suitable for the creation of fracture networks. Figure 6 is a demonstration of such a crossplot using the seismic data for the Colorado Shale Group, which consist primarily of Late Cretaceous shales. The result of applying this crossplot to the Second White Speckled Shale Formation of the Colorado Group is shown in Figure 7. The zones and cut-offs in the crossplot should be optimized through well control as the field is developed. Areas where the DHSR is small and Young’s modulus is large (green in Figure 7) are confined to small areas of this already small survey. These areas, such as the green

Figure 3 Minimum horizontal stress, h , showing the target Colorado Shale and the Second White Speckled Shale (2WS) formation within it. The coloured stripes at the well locations are the vertical stress, v , for reference.

Figure 4 Map of minimum horizontal stress, h, over the Second White Speckled Shale. Note its variability over a short distance from about 20 MPa around well 14-13 to 26 MPa around well 6-13. North is to the top and east to the right. The red line towards the top of the figure shows the location of the sections shown in other figures. After Gray 2010a.

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Figure 5 Brittleness in percent, estimated using our generalization of the methods of Rickman et al. (2008). The green stripes at the well locations are there because there is no equivalent brittleness log in the project.

Figure 6 Crossplot of DHSR versus Young’s modulus. Preferred areas for hydraulic fractur-ing are indicated in green, less desirable areas in yellow, and poor areas in red.

Figure 7 Map of Second White Speckled Shale showing zones highlighted in the crossplot in Figure 6. Green suggests where fracture swarms will form, red sug-gests the rocks are more ductile and thus less likely to fracture, and yellow suggests where aligned fractures are likely to occur. There are considerable variations in the north-central part of the survey, where the data suggest areas good and bad for hydraulic fracturing within about 100 m of each other.

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Kirsch’s (1898) concept of hoop stress (Figure 8) can be used to estimate PFB given the principal stresses that have been estimated already. Hoop stress is generated by the removal of a cylinder of material caused by the drilling of a well. By estimat-ing hoop stresses from the principal stresses derived earlier, we can get an idea of what will happen while drilling before a well is drilled. Here we assume that the pressure in the borehole is close to the formation pressure in this estimation (although if wellbore pressures, e.g. mudweights, are known then they can be used). Since from the above analysis we now have estimates of principal stresses everywhere, we can see what will happen everywhere before a well is drilled and thereby avoid areas where there are potential wellbore stability issues.

In Figure 9, we can see that there are potential vertical wellbore stability issues (green zones indicating very low PFB) in vertical wells in the Mannville coalbeds (below the Colorado

h, or H, as shown in Figure 1, is important information for optimal hydraulic fracturing of this reservoir. This rapid varia-tion in the stress direction is consistent with the interpretation of the causes of fracture orientation in underlying coalbeds and sandstones described by Gray (2005b). He ascribed these frac-tures to local stress induced by drape over underlying pinnacle reefs and differences in brittleness due to lithology. They could also be caused by differential compaction or collapse associated with underlying salt dissolution.

Areas indicated in red in Figure 7 have a low likelihood of fracturing and therefore should be assessed carefully before drilling. There will likely be difficulty fracturing these rocks. However, one possible reason for the low level of brittleness is high total organic carbon content, which is potentially beneficial to production. This reason is just one example of why all levels of brittleness should be properly assessed before proceeding with drilling, which can only be done with seismic data. Assume that one well per square kilometre is required to develop this shale gas play with drilling and completion costs of US$8 mil-lion per well, which are similar to numbers that are commonly reported (e.g., Crum, 2008), and assume that the areas in red in Figure 7 will not fracture. This study shows that only three-quarters of the prospect will fracture, meaning that two of the nine wells should not be drilled. The cost saving, by not drilling the two wells, would be $16 million, reducing the total cost to develop this 9 km2 area from $72 million to $56 million. These savings easily pay for the acquisition, processing, and analysis of the seismic data used to derive this information, and are in addition to the uplift in net present value derived by drilling and completing the best areas first and additional value of deriving field scale development plans (e.g., orientation of horizontal wells on a large scale for optimum pad placement and planning).

Figure 8 The hoop stress concept: ‘If a circular hole is made in a homogeneous body experiencing a homogeneous stress field, stress will concentrate around the hole since no force can be carried through the interior void. [This] Figure … shows the stress concentration around the hole in a body under uniaxial compression, of magnitude 1

R in the far-field, in the x-direction’ (Lund, 2000).

Figure 9 Fracture breakdown pressure (PFB ) at the side of a vertical borehole. Areas shown in green indicate areas of very low or negative PFB indicating a sig-nificant risk of borehole failure at these locations. Many of these are in the Mannville coals at about 1000 ms, which is not surprising, but there are also some in the primarily carbonate section under the unconformity marked by the blue line at about 1075 ms. This information has potential importance for drilling. The coloured stripes at the well locations are the vertical stress, v , for reference. After Gray 2010a.

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DiscussionIt has been demonstrated that seismic data can be used to estimate rock brittleness and stresses away from boreholes. The combination of these estimates allows for assessment of the potential for hydraulic fractures and geomechanical issues in boreholes before drilling any wells. An example from the Colorado Shale of Alberta is used to demonstrate the method. This method is based on physics and so is applicable in any shale gas play as well as any other play where hydraulic fracturing is being considered, such as tight gas sands, coalbed methane, and carbonates, and where stress or geomechanics are at issue, such as in heavy oil plays and new exploration. The seismic data should be used to extrapolate information derived at wellbores

Shale), which are expected, and in the carbonate section below the unconformity at the base of the Mannville section, which is unexpected. We can also drill wells in areas where the hoop stress is in a range such that the pressure generated in the well-bore during drilling is lower and the pressure generated during hydraulic fracturing is sufficient to overcome it and break the rock without damaging the casing. Since horizontal wellbores will be drilled here, we should examine the fracture breakdown pressure for a horizontal wellbore (Figure 10) before drilling. We can also estimate whether the fracture will initiate in the top of the borehole or on its side (Figure 11). The closure stress and rock properties, derived earlier, predict how the fracture will behave away from the borehole.

Figure 10 PFB at the side of a horizontal borehole. Lower values indicate where it is easier to initiate fractures from the side of the borehole. Values ranging from about 20 MPa to over 100 MPa show that it is important this information be considered in well planning. The target Second White Speckled Shale (2WS) Formation has moderate PFB of 40-50 MPa, which is significantly greater than its closure stress, indicating that a significant amount of force will be required to initiate the fracture at the borehole, but that once the fracture is initiated, then it should continue to propagate until the pressure drops below the closure pressure of 20-50 MPa. The coloured stripes at the well locations are the vertical stress, v, for reference. After Gray (2010a).

Figure 11 Difference of fracture breakdown pressure for a horizontal well, PFB(side) – PFB(top). Positive values mean that the fracture will initiate out of the sides of a horizontal borehole. Negative values mean that fractures will initiate from the top of the borehole.

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Received 24 January 2011; accepted 10 January 2012.

doi: 10.3997/1365-2397.2011042

to the inter-well regions. However, this analysis can be done without well information using measured seismic velocities and assumed petrophysical relationships. Once principal stresses are estimated, other useful stress estimates, such as hoop stress, can be used to predict how the well will behave while drilling and under stimulation.

ConclusionsThere is a tremendous amount of information on stresses and rock properties that can be estimated from wide-angle, wide-azimuth, 3D seismic data. The horizontal stresses derived from this method need to be calibrated to stress values estimated from well data. Once this is done, these stresses can be used to estimate various stresses likely to be encountered between wells. Furthermore, the elastic properties derived during this process, such as shear modulus, Young’s modulus, and Poisson’s ratio, which also require static moduli for calibration, can be used to estimate the brittleness of the rock between wells. This informa-tion can then be used to plan well paths and optimize hydraulic fracture programmes.

AcknowledgementsWe thank CGGVeritas, EnCana, Apache, Talisman Energy, Magnitude, Fairborne Energy, Nexen, Bill Goodway, Doug Anderson, Ron Larson, Jonathan Miller, Louis Chabot, Eric Andersen, Jared Atkinson, John Varsek, Tobin Marchand, Dominique Holy, Colin Wright, Wayne Nowry, Jessie Arthur, Philip Janse, Christophe Maison, Dragana Todorovic-Marinic, Christian Abaco, Lee Hunt, Scott Reynolds and Jon Downton.

Note(1) A short duration, small volume fracturing operations

where a small amount (<100 BBLS) of KCL water is pumped until fracture initiation. At that point the wing or frac valve is closed allowing the well’s pressure to fall-off naturally over the course of 24 to 48 hrs. (or longer).

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