Injection-induced stress and fracture orientation changes

$Page 1: Injection-induced stress and fracture orientation changes$
Injection-induced stress and fracture orientation changes

MAURICE B. DUSSEAULT Department of Earth Sciences, The University of Waterloo, Waterloo, Ont., Canada N2L 3Gl

AND

JOHN V. SIMMONS Department of Civil Engineering, James Cook University, Townsville, Queensland, Australia

Received October 3 , 1980 Accepted June 21, 1982

Examination of the field evidence suggests that induced vertical fractures in the cohesionless, shallow oilsand reservoirs of northeastern Alberta are unlikely to remain vertical when large volumes of hot fluids are injected into them.

Numerical models are assembled taking into account the appropriate material properties, model geometries, and boundary conditions in order to simulate as closely as possible the stress response of a reservoir to induced fracturing. The results suggest that generation of horizontal fractures is extremely likely and that thermal input enhances this probability. Overstress (above overburden) may be maintained by an elastic skin effect on the fracture boundary. Continued displacement and pore pressure permeation can overcome this overstress resulting in the cyclic stress buildup-breakthrough pattern reported in the literature.

The inadequacy of static geomechanical models (no fracture orientation change) is pointed out; correct simulation requires correct process comprehension.

L'examen des observations de chantier suggkre que I'hypothbse que les fractures produites verticalement restent verticales est improbable lors de l'injection de grands volumes de fluides chauds dans les rCsewoirs peu profonds de sables biturnineux non cohkrents du nord-est de 1'Alberta.

Des modbles numkriques sont assemblks en tenant compte des propriCtCs des matCriaux, des gComCtries de modbles et des conditions aux limites de fason 21 simuler le mieux possible la rkponse en contrainte d'un rkservoir ii une fracturation provoquCe. Les rksultats suggbrent que la gCnCration de fractures horizontales est trks probable et que l'apport thermique augmente cette probabilitb. Des surcontraintes (en excbs des contraintes gkostatiques) peuvent &tre maintenues par un effet de peau tlastique aux limites de la fracture. Le d6veloppement des dCplacements et de la diffusion de pressions interstitielles peut surmonter cette surcontrainte, conduisant au processus cyclique d'accumulation de contrainte-rupture rapport6 dans la littkrature.

La faiblesse des modbles gComCcaniques statiques (par le changement d'orientation des fractures) est mise en Cvidence: une simulation correcte nkcessite une bonne comprkhension des processus.

[Traduit par la revue] Can. Geotech. J., 19,483-493 (1982)

Introduction Induced fractures are employed in oil sands and heavy

oil development as a means of enhancing effective reservoir permeability or for introducing steam or air for heating the viscous hydrocarbons. Fracturing is initiated by injecting steam, air, or water into the reservoir at a sufficient rate and pressure to overcome the original minimum principal total stress and any cohesive strength the reservoir rocks may possess. Continued injection of air above the fracture pressure is used to maintain in-situ combustion. Steam injection is used as a means of introducing sufficient heat to decrease the bitumen viscosity and allow flow. There is evidence that massive continued injection of hot fluid into shallow cohesionless reservoirs that initially fractured in a vertical mode (u3 initially horizontal) will cause an increase in the horizontal stresses sufficient for the fractures to change orientation because the vertical principal stress becomes the minor stress. This article will attempt to explain and rationalize this phenomenon through examination of the

limited data available and by numerical modeling that employs a finite element scheme incorporating the major system characteristics as accurately as the data permit.

Reservoir geomechanical properties The Clearwater Formation is the most desirable

development reservoir in the Cold Lake oil sands area because it is relatively thick (20-45 m), laterally continuous, homogeneous, of high oil saturation, and bounded by zones of higher fracture resistance (Kendall 1977). The oil-rich reservoir has an average in-situ porosity of about 30% and the sands are entirely cohesionless, possessing no significant intergranular cementitious material that could give a stress-indepen- dent tensile resistance.

The sands, although cohesionless, are quite dense; assuming Poisson's ratio is 0.28, geophysical sonic log data yield a Young's modulus of the order of 7 GPa at the reservoir depth of 450 m. This sonic modulus, albeit somewhat lower than the dynamic moduli of cemented

0008-3674/82/040483-11$01 .OO/O 01982 National Research Council of Canada/Conseil national de recherches du Canada

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484 CAN. GEOTECH. 1. VOL. 19, 1982

sandstones (Jaeger and Cook 1969), is much higher than that of normal dense sands. Cyclic compressibility tests on materials above and below the Clearwater strata yield very low static compressibilities (Barnes and Dusseault 1982). Values of 0.2-0.6 X kPa-' have been measured. With a Poisson's ratio of 0.28, these laboratory data convert to a static Young's modulus of 1-2 GPa, which is assumed to be the absolute lowest irz-siru value because the specimens were somewhat disturbed. Thus, the materials are very stiff at in-situ stress levels in the undisturbed state. The choice of moduli for modeling is further discussed later in this article.

Steam injection technology Esso Resources Canada Ltd. have carried out exten-

sive in-situ oil sands pilot projects using wells drilled from surface in a closely spaced rectangular grid oriented about 45" az (Imperial Oil Limited 1978). Cyclic steam stimulation involves injection of steam which becomes a liquid within the reservoir. The injected volumes for one cycle may be as high as 7000 m3 of water per well, or of the order of 2% of the reservoir volume per well based on a 67 X 150m spacing. Injection occurs at many wells simultaneously and sequentially. Injection takes place in the lower portion of the target reservoir at a depth of about 460 m. Production is on a flow-back basis between steam injection cycles.

Other operators conducting field pilot projects in Cold Lake use other similar techniques, most of which involve massive cyclic or continuous fracture by injection of air or steam (Capeling and Peggs 1979; Towson 1979). Continuous fracturing must occur during the initial injection cycle because the reservoir permeability is low and injection rates are high.

Reservoir behavior during injection Once beyond the influence of borehole and packer

effects, the orientation of a fracture plane in a cohesionless reservoir is normal to the direction of minimum principal compressive stress (Hubbert and Willis 1957). In the Cold Lake deposit, at a depth of 450 m, fractures are vertical with about a 45" azimuth (Imperial Oil Limited 1978). The direction of u3 is therefore approximately parallel to the mountain front, similar to other Alberta data, and is considered to be related to continen- tal drift and consequent tectonism (Bell and Gough 1979; Gough and Bell 1980). The observed stress ratios in the Cleanvater reservoir at Cold Lake are (Imperial Oil Limited 1979):

Recent data (Holzhausen et al. 1980) for the Atha- basca deposit at a depth of 3 10 m suggest a ratio of 0.85.

This number is calculated after slow fracture initiation at injection pressures of 5600 kPa and a mean overburden density of 2.2 ~ ~ / m ~ . Other shallower sites within the Athabasca deposit indicate stress ratios of 1.0 and higher (Dusseault 1980a). These latter deposits fracture in shallow rising planes often referred to as horizontal fractures. Equilibrium of fracture growth seems not to occur in continuous fracture of the uncemented shallow oil sands (Holzhausen et al. 1980; Settari and Raisbeck 1979) such as the Cleanvater Formation because the processes of injection and reservoir heating induce large stress and pore pressure changes, and also perhaps cause

- -

changes in formation properties through heating, ero- sion, and remolding of oil sands. The fracture fluid properties may also be altered as eroded sand and bitumen become entrained during injection.

Although fracture growth takes place initially normal to the direction of a3, changes in stress fields may cause principal stress direction rotation, rendering the reservoir more susceptible to fracture growth in directions other than the original. The strains causing stress change are induced by heating (thermal strain) and fracture growth (injection strain). Because fractures open and widen normal to the u3 direction, the induced strains must increase u3. The value of the vertical stress cannot greatly exceed the overburden stress because the surface of the earth is a stress-free plane. Therefore, vertical stresses are limited, whereas the horizontal stress normal to the fracture plane can increase in direct response to the strains. Evidence has recently become available to suggest that the initial reservoir fracture direction changes and it is the goal of the numerical part of this paper to rationally model the stress changes associated with fracturing.

Thermally induced strains Thermal energy input through combustion or steam

injection will result in reservoir fluid and matrix expan-

TABLE 1. Reservoir properties

Reservoir fluid specific heat 740cal/("C.kg) Fluid thermal expansion coefficient 900x ~ o - ~ / " C Rock (SO2) specific heat 188cal/("C.kg) Rock thermal expansion coefficient -30x IO-~/"C

(assuming quartz only) Initial reservoir temperature 25°C In-situ volume compressibility (m,) 0.4-0.8 X 10-~k~a-'

Properties of 1 m3 of reservoir, 30% porosity Liquid volume, mass 0.3 m3, 300 kg Rock volume, mass 0.7 m3, 1855 kg Lumped average specific heat 570X 10~cal/("C.m~) Lumped thermal expansion coefficient -500X IO-~/"C

(assuming undrained behavior)

NOTE: 1 cal = 4.19 J.

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DUSSEAULT AND SIMMONS

a, = ay = 0 Boundary Om

1 I Glacial Deposits: Layers of Sand Gravel and Till I

-100m

Colorado Clay-Shales: Smectitic Very Clayey Mudstones; Extremely Uniform Lithology

Fracture Locations (one only for single fracture) I .

I \ Grand Rapids and Upper Clearwater Formations: I Silts, Clayey Siltsand Fine-Grained Sandstones I

-425 m

A# Clearwater Formation Rese~oir: Fine-Grained Sands I -455 m

I

Lower Clearwater and McMurray Formations: Silts and Sands I -515m

I I Carbonate Rocks: Limestones of Devonian Age I

Schematic Deformed Shape of a Fracture, Displacement Boundary Conditions, Quasi-Elliptical Distribution

T

It Fluid Injection Pointat H/3

\ M = 0 Boundary c- Ax = 0 Boundary

FIG. 1. Schematic model and fracture cross section.

M = ~y = 0 Boundary

sion. Much of this takes place long after the great majority of the injection-induced strains have occurred because fracture growth is an attenuating process whereas thermal energy input rates are constant. Table 1 gives typical and assumed reservoir properties for a quartzose oil sand.

Expansion of the rock matrix through heating is expressed as a reservoir volume expansion. Fluid thermal expansion will cause reservoir expansion only if fluid flow is impeded (partial drainage). This is unlikely on the time scale of reservoir heating, therefore com- plete drainage can be assumed. The change in temperature involved in reservoir heating is not sufficient to

cause large physico-chemical changes in the matrix behavior; therefore, assuming a constant value of the rock skeleton thermal expansion coefficient and no change in rock compressibility (Cb), the partial differential equation,

can be written as

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486 CAN. GEOTECH. J. VOL. 19, 1982

to calculate changes in mean effective (rock skeleton) 310-m depth. The experiment showed an initial injec- stress (6'). tion pressure of 5600 kPa (initial KO of 0.85). Gradual

Long-term heating may ultimately raise the mean increases of injection pressure to values about 1.15- reservoir temperature by 75"C, which would result in a 1.22 times overburden, followed by sudden drops to general effective stress level increase of 3.5 MPa if all about overburden, occurred repeatedly over a period of expansion were rigidly confined. Such is not the case, several weeks, each buildup taking from 1-3 days at and, furthermore, an overall temperature increase of approximately constant injection rates (Fig. 2). 75°C is expected to occur only after many years of steam These events are interpreted as vertical fracture injection. The thermal strains are therefore relatively development, stress buildup, and breakthrough in a small and delayed in time. The injection-induced strains horizontal or inclined fracture. Initial fracture propaga- are much larger than the thermal strains (Holzhausen et tion pressures of less than overburden confirm vertical al. 1980) and probably totally dominate behavior in the fracture development, and there is no evidence for early reservoir history. It was therefore decided to fracture growth in jumps, nor could such a behavior be numerically model only the injection strains. expected in a material with no significant tensile

Injection volumes and fracture thickness strength. The pressure drop to 6700-7100 kPa indicates a mean overburden density of 2.2-2.3 Mg/m3. Break-

The amount fluid in a sing1e a through releases the pressure on the vertical fracture, cyclic steam injection process is of the order of 7000 m3 closure and reinjection in the vertical frat- (Imperial Oil Limited 1978). Assuming a formation ture, followed by another cycle of gradual stress thickness 45 m y a spacing 67 accretion and breakthrough. Other postulates, such as 150 within which a fracture is and a per- rate effects or significant lithological changes, have no fectly uniform vertical fracture, a minhum thickness foundation in observed response data and are considered of 1 m is obtained. This is unreasonable, but uniformly less reasonable than the explanation presented. Injection shaped fractures exceeding several kilometres in length pressures at the well bottom in excess of overburden are If the fluid (loss pressure suggest that local elastic stresses somewhat in fluid from the fracture) is acceptably high, elliptical or excess of overburden can be temporarily maintained lens-shaped fractures several centimetres thick may be during constant injection rates. l-he assumption of created. Since the injection point is usually near the maximum injection stresses equal to the overburden formation base and the injection fluid pressure decreases stress ( ~ ~ b b ~ ~ and willis 1957) seems to be untenable towards the fracture tip, the deflected shape should be for high continuous injection rates of hot fluids in quasielliptic with extension of the vertical arm (Fig. 1). shallow cohesionless reservoirs: some local overstress-

There are not yet enough field data to confirm or deny ing does take place, these assumptions. The use of tilt-meter measurements to back-calculate fracture thickness (Wood et al. 1979) is constrained by the lack of actual measurements inside reservoirs, the uncertainty of the assumed deformational parameters, lack of knowledge of field stress distributions and bleed-off factors, and lack of uniqueness of the elastic analysis. Most other measurements, such as electrical field monitoring, seismic techniques, and post-fracture coring (Smith et al. 1978; Jones et al. 1980) yield data even more difficult to interpret and relate directly to fracture thickness during injection. Modeling tautology creates still another problem: the application of a model assuming a certain geomechanical behavior yields data that are often interpreted as being proof of the assumed mechanisms. Field data are becoming available in the public domain showing that some assumptions of reservoir behavior may be incor- rect, but the model assumptions herein remain largely assumptions, although it is felt they are the most appropriate for the limited data base.

Fracture direction change during injection Holzhausen et al. (1980) reported injection pressures

for a long-term injection experiment in a single well at

The numerical modeling scheme The finite element, two-step, linear elastic analysis

employed herein is not novel. The two-step analysis is the sum of the initial stress state and the induced stresses, yielding a final correct stress state and displacement field (e.g., Dusseault 1977). In geomechanics, we have in many areas approached the stage where our computational ability greatly exceeds our knowledge of material properties, and, more impor- tantly, the specific geomechanical processes taking place. Accordingly, the assumption of behavior and rationale for properties is of greater interest than the type of model employed and will therefore be emphasized.

The reservoir modelled is assumed to behave elasti- cally. This assumption is valid because plastic effects (nonrecoverable strains and remolding) would be expected to dominate only close to the fracture boundary. Because of high effective stresses, the reservoir history of overconsolidation, and the relatively small stress changes at any significant distance from the fractures, the assumption of linear elastic behavior is rational.

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Initial Breakdown I ,pressure

1-4 8018112 (date of event)

1 k Very Sudden Pressure Drops

I overburden Stress Assuming y = 2.25 - 12 h

F= Initial Shut-In Pressure (KO " 0.85)

Time (scale not continuous)

FIG. 2. Cyclic pressure drops during steam injection (only 4 of 8 events represented; adapted from Holzhausen et al. 1980).

Linear elastic fracture mechanics are not employed, nor has a propagation function been incorporated.

Data from Cold Lake suggest that vertical fractures are confined within the Clearwater Formation reservoir, therefore a vertical fracture extending the height of the reservoir is modelled. The confinement in Cold Lake is the result of a barrier that is resistant to fracture penetration. Recent investigations (Warpinsky et al. 1978) have shown that fracture toughness variations have little effect on a fracture propagating normally towards an interface; therefore the barrier effect may be related to higher original horizontal stresses, to higher induced horizontal stresses arising from the fracturing operation itself, or to a pore fluid effect. Sonic data do nbt reveal thick barriek of differing moduli, which Constant ~uasi-~11iptica1

would seem necessary for the maintenance of higher C~r,?;iE:,",y Displacement Displacement Condition Condition

stresses, therefore no differential horizontal stress dis- Location

tributions are assumed for the reservoir. The models employ a grid of six differing strata with a

symmetric plane strain configuration (Fig. 1). Sym- metry is justified by the flat-lying reservoir geometry; the six-fold lithological division is an attempt to accurately model field conditions and the plane strain model is felt to be adequate for a fracture several times longer than its height.

The first model is a single vertical fracture using a displacement boundary condition on a mesh of four- node elements (101 elements, 11 5 nodes). A uniform 10-mm displacement (Fig. 3) was found to cause stress concentrations at high curvature points and showed only

FIG. 3 . Fracture displacement boundary conditions, single fracture model.

local effects despite the system stiffness. A quasi- elliptical nodal displacement scheme was applied there- after (Fig. 3).

The second model is geometrically identical to the first except that three equally spaced (130 m) fractures are modelled and very fine subdivisions are used. The inner mesh is composed of eight-node isoparametric elements, the outer mesh of four-node elements (142 elements, 339 nodes). Compatibility along the boundary of the two element types is enforced by an element

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CAN. GEOTECH. J. VOL. 1 9 , 1 9 8 2

Depth (rn)

425

Boundary Condition (MN)

0.0 Displacement

455 9.1 I---%?---/ 2.73 0.0 Displacement

FIG. 4. Derivation of nodal traction boundary conditions for a vertical fracture.

formulation possessing optional midside nodes (Bathe and Wilson 1977). At fracture tips, side nodes are placed at the quarter points closest to the fracture tip, thereby aiding in representing strain singularities (Ingraffea 1977). Opposite sides of the fractures are totally decoupled: they may move entirely independently. All stresses are solved at the element Gaussian points and plotted. A sufficient number of elements and nodes are employed to assure smoothness of the stresses and the validity of the solution. Computer plots of the ratio of final to initial vertical stress (uVf/ovi), KO (i.e., u H / u v ) , and the direction of ug were generated for the inner portions of the mesh. Because of the difficulties of modelling interacting displacement fields between fractures, the three-fracture model was subjected to stress boundary conditions derived from the displacement analysis of the single-fracture model.

To derive a boundary traction for the three-fracture model, a maximum pressure at the injection point is assumed.

Figure 4 shows the full derivation of the tractive boundary condition.

Choice of material properties for analysis Static laboratory tests on oil sands and related strata

yield deformation moduli much lower than those in situ because of sample disturbance (Dusseault 1980a). In-situ static deformation moduli are not available. Sonic transit-time data (P-wave only) are available from geophysical data, and Young's modulus may be com- puted from those data if a reasonable Poisson's ratio is assumed. However, dynamic elastic constants differ from the static values: in general, higher values of Young's modulus and Poisson's ratio are obtained dynamically (Lama and Vutukuri 1978). The ratio of dynamic to static modulus is commonly 1.5-3.0 for non-cemented strata at the effective stress levels of interest. To be conservative, two sets of Young's moduli were used in analysis: a soft set and a stiff set with ratios of about 6.0 and 2.0, respectively, to the dynamic moduli (Table 2).

In flat-lying strata the geophysical sonic log measures the velocity through the bedding whereas the values along the bedding are about 1 .O- 1.3 times higher (e.g., Lama and Vutukuri 1978). The analytic values were not increased to account for a directional difference in

Since KO = 0.8, the stress applied to the weightless medium in analysis is

[5] paPp1 = P,,, - K,,YZ = 1 . 3 ~ ~ - 0 . 8 ~ ~ = 0.5yz (maximum) moduli because the goal of the analysis is to model stress

response in a medium of stiffness equal to or slightly less than that in situ. Non-cemented uniform sandstones

The applied pressure is

respond quite isotropically to induced strains; therefore, other than the moduli differences between lithologies, no anisotropy was included in the analysis. The stiffer moduli are believed to be closer to the actual in-situ values. The authors feel that the use of excessively soft

where a = 0.5 at the injection point and is distributed quasi-elliptically to a = 0 at the fracture tip to account for viscous pressure losses and the inability of a cohesionless medium to withstand excess pressure at a fracture tip. moduli is not analytically justified; if the correct

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0.95' - /'

/ 0.90-- Grand Rapids Formation /,/'

Zones of Stress Concentrations

Clearwater Reservoir

McMurray Formation / / ('0 85

/ / \0.9oi- 0 95

1 \\ -. -___-- -


Boundary Displacement

FIG. 5. Uniform boundary displacement of soft strata, contours of avf/avi (avf = final stress; a,i = initial stress). Refer to Table 1 for soft properties.

geomechanics are formulated, then the appropriate moduli will yield the right answers without manipula- tion.

No paradigm of the geomechanical processes that take place during hydraulic fracture is totally accepted; the approach herein is considered the most basic one consistent with well-established geomechanics prin- ciples.

Model use and results The initial simulation used a 10-mm uniform dis-

placement on a single-fracture model. Stress concentrations at high curvature points and the local nature of stress changes were the major effects (Fig. 5).

The single-fracture model was then subjected to two different quasi-elliptical displacements employing the two sets of material properties referred to as soft and stiff. Results of these four analyses are plotted in Fig. 6.

It may be concluded that, even for small displacements in a soft medium, the condition KO > 1.0 may be reached. The asymmetric distributions of the stress ratio are due to differing layer stiffnesses and the shape of the boundary displacement. If the model assumptions are all tenable, inclined fractures should be generated eventu- ally with breakthrough near the injection point rather than higher in the strata. The added effect of temperature

m m m m c l m z v ? z 2 2

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492 CAN. GEOTECH. J. VOL. 19, 1982

Overlying Clearwater and Grand Rapids Formation

__/---- '. . /- - ,

/ \ , \ /

/

\ /

\ / /

'L /

I 0.8 0.9

\ / /

, '\ I \ -

/ / - - _

Clearwater Formation Reservoir

Fracture McMurray Formation Fracture

I

FIG. 7. Contours of KO(uh/uV),

will be to increase KO values more as temperature- induced stresses are partially relieved vertically, but strains are confined laterally. In this sense, the analysis is conservative. The maximum pressure boundary conditions that could give rise to a stress field of this magnitude is about 1.3yz or an a of about 0.5 (see [6]).

The triple-fracture model was subjected to an elliptically distributed pressure of a = 0.5. The extent of regional stress changes can be seen in Fig. 7. Again, the effects of injection can be seen as a general increase in the value of KO above its initial value of 0.8, even within a soft medium (although this is not an important variable for a pressure boundary condition). Because the spacing of 130 m between fractures is conservative (prototypes will tend towards a spacing of 60-loom), more interaction can be expected in large-scale operations.

The regional stress changes arising from injection can be significant in these shallow, cohesionless low-stress reservoirs. The models used here suggest that a fracture direction change is not only probable, but unavoidable if sufficient fluid is injected, at pressures above that necessary for fracture, into a cohesionless bounded reservoir of low permeability. Other associated phe- nomena may occur, such as stick-slip movements, casing distress (Smith and Patti110 1980) and seismic energy emission (Dusseault 1980b), but these phenom- ena are as yet insufficiently documented to incorporate into the above conclusions.

The fracture stress skin and pore pressure effects The increase in stress parallel to the fracture plane

(u,) is significant, resulting in an overstressed skin close to the fracture (Fig. 8). This figure suggests that, in an impermeable bounded medium, a fracture can maintain a significant overstress (with respect to overburden) before fracture breakthrough occurs. As the horizontal stress is increased upon pressurization, the vertical stress also increases, particularly close to the fracture wall, causing the KO > 1.0 zone to be shifted away from the fracture wall. Breakthrough therefore does not occur when KO > 1 but at some overstress p > pyz where p, instead of being =1.0, probably lies in the range

three-fracture model, soft case.

Force BC as in Figure 4

Overstressed Skin '.,

FIG. 8. Normalized final vertical stress: the fracture skin effect (solid contours are uVf/uvi).

1.1-1.3 (for the cohesionless oil sand material) and is required to overcome the stress skin effect.

Maintenance of fluid pressure against a fracture wall in a permeable medium results in pore pressure increases in the adjacent walls. The total stress is not affected by pore pressure transients but, when the pore pressure exceeds the total stress locally in the zone of KO > 1 .O, a near-horizontal (or an inclined) fracture will be formed and breakthrough from the master vertical fracture will take place. This will cause a sudden pressure drop until the horizontal fracture is sealed from the original vertical fracture by the overstressed fracture skin, and pressure buildup again takes place. This interpretation explains pulsations observed in field tests previously discussed (Holzhausen et al. 1980).

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DUSSEAULT AND SIMMONS 493

Conclusions On the basis of the limited field data available and the

analyses presented herein, fracture orientation changes must occur during continued injection into the shallow low-permeability cohesionless oilsands. The orientation change is the result of induced stresses. The implication is that, at present, geomechanically static simulators (one fracture orientation only) are inadequate for temperature-volume history matching. Consequently, pre- dictions based on the results of simulators that d o not incorporate the correct geomechanics can only be relied upon to the point where fracture-induced orientation changes commence.

The use of correct moduli, in-situ stresses, and geometric boundary conditions has occupied most of this paper and must again be emphasized. For stress analysis, the meshes employed were much too extensive and the detailed lithostratigraphy incorporated was unnecessary; however, for surface strain-pattern matching, the models could have been larger but with fewer mesh subdivisions in the central region.

The pursuit of correct material properties and correct geomechanical processes remains a valuable goal in this area of earth science: our knowledge of analytical techniques remains ahead of our knowledge of system behavior and of our capacity to apply techniques to changing conditions during fracturing operations.

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BATHE, K. J., and WILSON, E. L. 1977. Numerical methods in finite element analysis. Prentice-Hall, Englewood Cliffs, NJ, 528 p.

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Injection-induced stress and fracture orientation changes