Rock mechanics and stimulation aspects of horizontal wells

Journal of Petroleum Science and Engineering 25 Ž2000. 187–204 www.elsevier.nlrlocaterjpetscieng

Rock mechanics and stimulation aspects of horizontal wells M.Y. Soliman ) , Paul Boonen Halliburton Energy SerÕices, P.O. Box 819052, Dallas, TX 819052, USA Received 26 June 1999; accepted 3 December 1999

Abstract In certain reservoir conditions, horizontal wells can offer significant production improvement over vertical wells; however, fracturing is often required to maximize the return on investment for these wells. Since its introduction in the late 1980s, the practice of fracturing horizontal wells has become a viable completion option. This is especially true in the case of tight gas formations. This paper reviews best practices in the fracturing of horizontal wells and includes a discussion on the rock mechanics, operational strategies, and the reservoir engineering aspects of fracturing horizontal wells. The rock mechanics discussion reviews the theoretical and experimental work and creation of: Ž1. transverse and longitudinal fractures, Ž2. multiple fractures, and Ž3. fracture reorientation among others factors that are associated with creation of a fractured horizontal well. Stability of the horizontal well as it relates to stimulation is also discussed. The reservoir engineering portion discusses the production performance and testing aspects of a fractured horizontal well. Emphasis is given to fracturing tight gas formations since this area is the one in which this technique is considered to be the most effective. The performance of a longitudinal fracture is examined and compared to a fractured vertical well and to the more popular transverse-fractured horizontal well. Because performance of a longitudinal fracture is similar to that of a fracture in a vertical well, the existing solutions for fractured vertical wells may be applied to longitudinal fractures. This approximation is valid for moderate to high dimensionless fracture conductivity. In the case of transverse fractures, the outer fractures outperform the inner fractures. However, for most cases, more than two fractures are necessary to efficiently produce the reservoir. Operational aspects of fracturing horizontal wells for both transverse and longitudinal fractures are discussed, and advantages and disadvantages of each type are outlined. Examples and case histories are given. The paper also presents guidelines for stimulation of a horizontal well and includes both propped-and acidized fracturing as well as matrix acidizing. q 2000 Elsevier Science B.V. All rights reserved. Keywords: horizontal well; fracturing; rock mechanics; wellbore stability

1. Introduction Although unstimulated horizontal wells have been successful in naturally fractured reservoirs and in )

Corresponding author. Tel.: q1-972-418-3026; fax: q1-972418-3026. E-mail address: [email protected] ŽM.Y. Soliman..

reservoirs with gas or water coning problems, there are certain situations where fracturing a horizontal well to improve production capability is a viable option. The final orientation of a fracture is only dependent on the orientation of the stress field. Thus, control of the relative orientation of the fracture with respect to the wellbore Žtransverse or longitudinal. must be considered before the well is drilled. The appropriate contingency plans should be made to

0920-4105r00r$ - see front matter q 2000 Elsevier Science B.V. All rights reserved. PII: S 0 9 2 0 - 4 1 0 5 Ž 0 0 . 0 0 0 1 2 - 7

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anticipate possible low production from an unstimulated well. Fracturing a horizontal well may dictate direction in which the well should be drilled and how it should be completed, i.e., cemented and cased vs. open hole. Fracturing a horizontal well can be considered when one of the following situations is apparent: Ø Restricted vertical flow caused by low vertical permeability or the presence of shale breaks, Ø Low formation productivity due to low formation permeability, or Ø Low stress contrast between the pay zone and the surrounding layers. In the last case, a large fracturing treatment of a vertical well would not be an acceptable option since the fracture would grow in height as well as length. Drilling a horizontal well and creating either several transverse or longitudinal fractures would allow rapid depletion of the reservoir through the fractureŽs.. Although fundamentally similar to fracturing vertical wells, fracturing horizontal wells has unique aspects that require special attention for the most successful treatment. Differences between horizontal and vertical wells exist in the areas of rock mechanics, reservoir engineering, and operational strategies. Initially, the basic rock mechanics aspects should be examined.

Fig. 1. Typical failure envelope. To , uniaxial tensile strength; Co , uniaxial compressive strength; 1, Mohr circle corresponding to uniaxial tensile test; 2, Mohr circle corresponding to uniaxial compressive test; 3, Mohr circle corresponding to a triaxial test Ž s2X seff. confining pressure..

fail when the circle touches, and then, crosses over the failure envelope. A linear or preferably a parabolic failure envelope such as in Fig. 1 needs to be constructed from core tests. Without core data, an initial shear stress is computed from an equation developed by Deere and Miller Ž1969. and Coates and Denoo Ž1981., and the friction angle is put at 308.

2. The Mohr–Coulomb failure criterion

3. Stress distribution around a horizontal well

Mc Lean and Addis Ž1990. conclude that a linear failure criterion Ži.e., Mohr–Coulomb. is the most applicable in wellbore stability analysis, and a review of the literature on rock mechanics and borehole stability seems to confirm that this criterion is the most widely used. Such linear models, however, predict failure of the rock too early. Fig. 1 represents a Mohr–Coulomb analysis. The previously computed radial and tangential stresses are plotted on the x-axis of normal effective stresses. A Mohr’s circle is drawn through these two points. The failure envelope defines the stress conditions at which the formation will fail from shear failure Žsanding.. When the circle grows, for instance, by reducing the wellbore pressure, the formation will

The basic equations describing the stress distribution around a horizontal well may be derived from the analysis developed by Kirsch, Ž1898. and Fairhurst’s Ž1968. solutions for a vertical well, and Bradley’s Ž1979. equations for stress distribution around a deviated well. Mechanical borehole analysis consists of two steps; first, the stresses around the borehole are computed, and then, these stresses are compared to the strength of the formation. A number of models can be used to evaluate the stress field around a borehole, assuming from simple to complex — a linear-elastic, a non-linear-elastic, or an elastoplastic behavior of the rock, with or without considering such parameters as thermal effects or osmotic pressures. The most commonly used failure criterion

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seems to be the Mohr–Coulomb criterion, but Hoek–Brown, Drucker–Prager and other models have also been used. The main advantage of using the basic linear-elastic models is that the number of parameters is limited, and these can be assessed relatively easily. Linear-elastic models are, however, too simple and can predict failure of the rock too early. The stress distribution around a horizontal well follows the same equations as those used for deviated and vertical wells. The equations for the radial, tangential and vertical stress for a horizontal well may be derived from the equations for a deviated well and are shown in the following equations. For s H ) sv

sr s pi

Ž 1.

su s 3 sv y s H y pi

Ž 2.

sz s s h y 2 Õ Ž s H ysv .

Ž 3.

For s H - sv

sr s pi

Ž 4.

su s 3 s H y sv y pi

Ž 5.

sz s s h y 2 Õ Ž svys H .

Ž 6.

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Fig. 2. Horizontal borehole orientation with respect to the in situ principal stresses.

relative values of stresses is presented. Here, the vertical stress is the largest. This figure indicates that the horizontal wellbore is most stable when drilled in the direction of minimum stress. In addition, a region of wellbore stability considering both the tensile and compressive failure is shown. This region is widest when the wellbore is drilled in the direction of minimum stress. Therefore, it is safest when the well is drilled in the direction of minimum stress. Hsiao presented other examples with varying relative stress values that may give somewhat different conclusions.

4. Horizontal wellbore stability Eqs. 1–6 describe the stress distribution in the direction of one of the principal stresses in the horizontal wellbore. Fig. 2 is a schematic diagram of stresses and wellbore direction. If the angle b is set at zero and the angle a is 908, the horizontal well will be parallel to minimum stress, and Eqs. 1–6 will yield the stress distribution around a horizontal wellbore. If the well is at an angle to the minimum stress, shear stress will affect stability, and in the case of tensile failure, it will affect fracture propagation, leading to the formation of ‘‘steps’’ due to shear failure. Hsiao Ž1988. also studied the effect of fluid flow on stability of the horizontal wellbore. Fig. 3 is an example that was presented by Hsiao Ž1988. showing that stability of a horizontal wellbore depends on wellbore geometry, fluid properties and relative values of stresses. In Fig. 3, the most plausible case of

5. Borehole breakout analysis Redistribution of stresses around the borehole creates stress concentrations in the direction of minimum and maximum stress. The magnitude of these stress concentrations Ž sA and s B . can be computed from Kirsch, Ž1898. ŽFig. 4..

sA s 3 s H y s h s B s 3s h y s H

Ž 7. Ž 8.

The stress at the intersection of the minimum horizontal stress and the borehole Ž sA . is greater than the stress at the intersection of the maximum horizontal stress and the borehole Ž s B .. Breakout will occur at the intersection of the minimum stress and the borehole wall. Hence, a measurement of the direction of the borehole breakout provides the orientation of the stress field. A breakout is the evidence

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Fig. 3. Borehole operating pressure Žafter Hsiao, 1988..

of wall yield Žthe formation strength at the borehole wall is exceeded.. A breakout is not considered to be a borehole failure since the borehole remains useful. Borehole breakout can be measured using four- or six-arm caliper tools. The preferred tool, however, is the ultrasonic imaging tool, which makes up to 200-caliper measurements at every depth level. The image analysis software presents continuous images of the travel-time measurement and provides crosssections of the borehole at any depth. Since the

images are oriented, the direction of the breakout can be read, and therefore, the orientation of the stress field. Borehole breakout is very well defined Žin Fig. 5. to the NE and SW of the caliper cross-section. Minimum horizontal stress is oriented in this direction. The natural fractures have a direction perpendicular to the minimum horizontal stress as shown in the amplitude and travel-time images. The direction

Fig. 4. Directions of borehole breakout and fractures in relation to the orientation of the horizontal stress field.

Fig. 5. Ultrasonic imaging log showing natural fractures with a cross-section showing borehole breakout in a NE–SW direction.

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and dip of the fractures has been computed and presented in dip-meter format in track 2 as sharply dipping to the SW.

6. Fracturing failure criteria for transverse fractures Hubert and Willis’ Ž1957. failure criterion is commonly used to predict the breakdown pressure of vertical well. In vertical wells, fractures are usually axial, and consequently, the failure criterion occurs when the tangential pressure is less than zero. In other words, the tensile breakdown pressure for a vertical well under this failure criterion is given by the following equation: p b s 3s h y s H .

Ž 9.

Depending on the relative value of stresses, one may apply the same criterion to horizontal wells using Eqs. 2 and 5. Since vertical stress is usually the largest of stresses, applying Hubert and Willis’ failure criterion to horizontal wells ŽEq. 2. yields the following equation: p b s 3 sv y s H

Ž 10 .

Laboratory observations by El-Rabaa Ž1989. and Soliman Ž1990., and field observations by Weijers et al. Ž1992. show that Hubert and Willis’ Ž1957. failure criterion underestimates the breakdown pressure for a transverse fracture. This is basically because this failure criterion assumes the creation of an axial fracture. Weijers et al. could not correlate the fracture initiation pressure and the tensile failure solution. While this criterion ŽHubbert and Willis. is valid for a vertical well or a horizontal well where the fracture is longitudinal, it does not fit a situation in which the fracture is transverse. In 1990, Soliman applied Hoek and Brown’s Ž1982. failure criterion to fracturing a horizontal

Fig. 6. Fracturing pressures from arbitrarily oriented horizontal wells in a North Sea chalk formation Žafter Owens et al., 1992..

well. Žcreating a transverse fracture.. The breakdown pressure under this failure criterion is given in the following equation: 1 s l y s L q sc Ž 11 . 2 2 where s L is the largest of sv and s H ; s l is the smallest of the two, sc is the compressive strength of the rock. This failure criterion was applied to laboratory experiments for fractured horizontal wells with reasonable success. Table 1 is a comparison of observed vs. calculated breakdown pressure for a transverse fracture. The relative magnitude of the breakdown pressure clearly indicates that under the same stress field, it is easier to create an axial fracture than a transverse fracture. This fact will explain the sometimes-complex path that arises while fracturing a horizontal well. Owens et al. Ž1992. presented another approach for calculating the breakdown pressure of an arbitrarily oriented horizontal well. In their approach, Owens et al. used the equations developed by Daneshy pb s

3

Table 1 Comparison of breakdown pressure calculation Experiment group

Observed pressure, psi ŽkPa.

Calculated pressure using Hubert and Willis’ Ž1957. criterion, psi ŽkPa.

Calculated pressure using Hoek and Brown’s Ž1982. criterion, psi ŽkPa.

HZ-1 HX-2

2850–3850 Ž19,650–26,545. 3400–4250 Ž23,442–29,303.

1750 Ž12,066. 1750 Ž12,066.

3275 Ž22,580. 3600 Ž24,821.

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Fig. 7. Nonplanar fracture geometry Žafter Abass et al., 1992..

Ž1973. and the Willis and Hubert failure criterion to calculate fracture initiation pressure. They compared their calculated values to observed field data from a North Sea field ŽFig. 6..

7. Fracturing a horizontal well The angle between the horizontal well and the minimum stress is crucial in determining whether a planar transverse fracture, or a complex non-planar fracture is created as shown by Daneshy Ž1973. and Abass et al. Ž1992.. This is illustrated in Fig. 7. A complex fracture shape could result in a tortuous flow path that could lead to a higher-than-expected

Fig. 8. Fracture reorientation Žafter El-Rabaa, 1989..

Fig. 9. Steps occurring during fracturing of deviated wells Žafter Daneshy, 1973..

propagation pressure. Sometimes, a fracture may initiate at an angle that is less than 908 to the minimum stress. As the fracture propagates into the formation, it reorients itself into a direction perpendicular to minimum stress. The process was studied first for deviated wells and more recently for horizontal wells. The fracture reorientation shown in Figs. 8 and 9 were the results of experimental studies. Using a numerical simulator, Olson Ž1995. developed a simple relationship between the closure stress and horizontal azimuth. This relationship is presented in Fig. 10. On the other hand, Siriwardan and

Fig. 10. Variation of closure stress with wellbore azimuthal deviation from optimal fracture direction Žafter Olson, 1995..

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Layne Ž1991. presented a simplified solution to predict simultaneous multiple fracture propagation. Using their simulator, they studied the effect of several parameters including wellbore friction pressure, entry friction pressure, and fracture orientation on the created fractures.

As a result of the very short perforated interval, one should expect very high near-wellbore friction due to perforation, multiple fractures, and tortuousity. Abou Sayed et al. Ž1995. reported up to 14,796 kPa Ž2146 psi. of near-wellbore pressure drop due to friction.

8. Creation of transverse fractures

9. Creation of longitudinal fracture

As mentioned above, the natural tendency of the fracture is to be axial. In addition, an axial fracture would initiate and propagate at a lower pressure than a transverse fracture. Thus, the tendency would be that even if the wellbore were in the direction of minimum stress, an axial fracture would be created in addition to the transverse fractures. El-Rabaa Ž1989. studied this problem and concluded that to prevent the creation of axial fractures, the perforated interval should not exceed four times the diameter. The effect of the length of the perforated interval was studied by El-Rabaa Žshown in Fig. 11.. The figure indicates that as long as the perforated interval is less than the twice the diameter, a single transverse fracture would be created. If the diameter exceeds twice the diameter of the wellbore, multiple fractures can be created. Field studies, however, indicated that relaxing this condition somewhat might be acceptable. Using a perforated interval of up to 2 ft, or four times the diameter of the well, has been successfully applied in field operations.

If the horizontal well is drilled in the direction of maximum stress, the fracture will propagate in the direction of the wellbore. If the perforated interval is long Žor if the well is not cemented and cased., an axial, longitudinal fracture will be created. Because it is easier Žlower breakdown pressure. to create an axial than a transverse fracture, the tolerance for deviation from the direction of maximum stress may be high. However, deviation from the preferred direction will Žas in case of transverse fractures. cause the fracture to reorient itself in space, potentially causing a host of problems as will be discussed in Section 10. Longitudinal fractures have not been as applied in field development as often as the transverse fractures. This is principally because of the reduced coverage of reservoir volume that they provide compared to a number of transverse fractures with equal total surface area. Only recently has the application of longitudinal fractures become significant.

10. Transverse vs. longitudinal fractures

Fig. 11. Effect of perforated interval on fracture initiation Žafter El-Rabaa, 1989..

Depending on the depth and placement of the horizontal well, the operator may have a choice between creating a transverse or a longitudinal fracture. One disadvantage of transverse fractures is that miscalculation of stress orientation can result in a rough sand face as the fracture turns perpendicular to the least principle stress. This could lead to an early sandout or screening-off during the fracture treatment. Although stress orientation is an important consideration for longitudinal fractures, it is less critical in that the fracture will tend to propagate along the well for some distance before it changes in orientation. Production rates may be less than for a well with transverse fractures.

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To reduce the dependence of transverse fractures on stress orientation and to maximize the chances of creating a single transverse fracture, it has been recommended that the fracturing treatment be preceded by an acid treatment. The main purpose for creating multiple transverse fractures is to accelerate the rate of hydrocarbon production. Another important advantage is that multiple fractures are normally fairly small, which reduces the chances of penetrating the surrounding zones. Thus, a source of potential problems is avoided. Some evidence exists ŽOlson, 1995. that transverse fracture widths near the wellbore may not be as large as commonly used theory predicts. This could lead to potential operational problems such as high friction pressure and premature sandout. An advantage realized from longitudinal fractures is that it is possible to create a series of fractures that span the entire length of the horizontal well. Each fracture is small, and as in transverse fractures, the potential for penetrating the surrounding zones is minimized. It is also possible to create the axial fracture in an open hole. In extreme cases, this could be done in one step. Based on laboratory observation, the authors believe that regardless of stress orientation, the fracture will probably be axial. However, to minimize the effect of reorientation, it is advised to keep the orientation of the horizontal well within 158 from the direction of the maximum horizontal stress. Although a cost saving is usually achieved, creating a longitudinal fracture in an open hole has several potential problems and will work best in a homogenous formation where the possibility of creating a continuous fracture is maximized. Review of transverse and longitudinal fracture performance indicates that below a dimensionless fracture conductivity, CfD, value of 5, a transverse fracture may not be cost-effective. It would not be prudent to recommend multiple transverse fractures in high-permeability formations. However, because of the short distance fluid travels inside the fracture, a longitudinal fracture is suitable for high-permeability formations. Another potential problem in cleaning up fracturing fluids can also occur. The necessity of high-fracture conductivity to efficiently clean up a fracture has been presented in Soliman and Hunt Ž1985.. The convergence of streamlines toward the

wellbore in cases of transverse fractures makes the need for high-fracture conductivity even more critical.

11. Reorientation of fractures If a fracture initiating from the wellbore is at an angle to the minimum in situ stress, the fracture will have to eventually reorient itself in a direction perpendicular to minimum stress. In a comprehensive analysis of this fracture reorientation process, Daneshy Ž1973. observed that the reorientation surface takes the form of steps ŽFig. 9.. These steps are the result of both tensile and shear failure. The presence of steps not only contributes to the abnormally high fracture propagation pressure, but it may also lead to a premature sandout. The analysis performed by Hsiao Ž1988. re-confirmed Daneshy’s results that shear stress plays an important role in stability of horizontal wells that are at an angle to the direction of minimum stress. Other authors have argued against considering the ‘‘steps’’ as caused by shear failure. Baumgartner et al. Ž1989. suggested that fracture initiation and propagation from a deviated well is due to tensile failure only. Hallam and Last Ž1990. suggested that the steps observed by Daneshy Ž1973., El-Rabaa Ž1989. and Abass et al. Ž1992. are starter fractures that may or may not communicate. Regardless of the mode of failure behind the reorientation of the fracture, the process will create a narrow, effective fracture width that could contribute to high fracturing pressure. Still worse, the narrow fracture width could trap proppant and eventually cause sandout. Soliman Ž1990. expanded on Daneshy’s work by studying microfracturing of deviated and horizontal wells. He concluded that analysis of microfractures and minifractures conducted on deviated wells would yield values higher than minimum stress because of the combined effect of maximum stress and shear stress. To minimize this effect on stress determination, he has recommended that a larger-than-usual microfracture test be run. An alternative would be to run various tests to determine not only the minimum horizontal stress but also the maximum horizontal stress.

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Experimental and analytical studies have shown that the reorientation radius increases as the pumping rate increases. It has been also found that as the ratio between the maximum and minimum horizontal stresses increase, the reorientation radius gets shorter. Using the analysis developed by Viola and Piva Ž1984., El-Rabaa Ž1989. developed a relationship between the reorientation radius and the stress ratio. The work El-Rabaa has done indicates that for a stress ratio of higher than two, it is unlikely that a fracture in the direction of the minimum stress will be created. One has to remember that Viola and Piva’s study was strictly analytical and that it only provides guidelines. When a fracture is reoriented in space, it is expected that the fracture width will be reduced. The degree of reduction in the fracture width depends on the degree of orientation. A fracture created axially to the wellbore that turns to a perfectly transverse fracture would suffer maximum reduction in width. Deimbacher et al. Ž1992. presented a simple equation to calculate this width reduction. wl wt

s 1.5

d

Ž 12 .

l

Where d s well diameter; l s perforated interval; w l s fracture width during reorientation process; wt s fracture width with no reorientation. If the well is at an angle, a , from the well trajectory, the following equation describes the reduction in width: wl wt

s 1.5

d l

Ž 1ycos a . q cos a

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The following equation gives the anticipated reduction in width. w l ( wt

p L2 2 L1

Ž a p y s3 . p y s 3 Ž m 2 y rl 2 .

Ž 14 .

From laboratory analysis, if the perforated interval is less than four times the diameter, only the transverse fracture will be created. Although the above equations may not be quantitatively valid, qualitatively they indicate a definite drop in the width of the fracture as the fracture is reoriented. This reduction in width could cause premature sandout, and even when achieving the designed fracture propagation, the lower width would cause a sharp decline in conductivity, and in turn, would reduce the well productivity.

12. Multiple fractures at end and away from the wellbore It has been shown that multiple fractures may be created when fracturing deviated or horizontal wells. This situation may be due to inclination of the wellbore to the minimum horizontal stress andror the presence of a long perforated interval. Fig. 12 gives an example of the presence of multiple parallel fractures. These fractures may propagate simultaneously, at least initially. As the fractures propagate, one set of fractures will become dominant while growth of the rest of the fractures would be arrested.

Ž 13 .

Eq. 13 indicates that if the perforated interval is more than 1.5 the diameter, a reduction of width would occur. El-Rabaa and Rogiers Ž1990. presented a significantly more comprehensive approach to the above problem that would take into considerations not only the stresses relative values but also the size of the created fracture. Thus, the width of the fracture is more than just a simple geometric function of the relative orientation of the stresses and the wellbore.

Fig. 12. Multiple parallel fractures initiated from an open hole Žafter Abass et al., 1992..

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The presence of multiple fractures will cause the fractures to be narrower than expected, which in turn, will cause: Ø Ø Ø Ø

High friction pressure High propagation pressure High leak-off rate due to the high surface area Possibility of sandout.

It is important to avoid the presence of multiple fractures and to keep good communication between the wellbore and the main fractures. This may be achieved through proper design of the perforated interval; number and orientation of perforations; and stress orientation. From their experimental work, Weijers et al. Ž1992. observed that when trying to create transverse fractures, one of the following fracture geometry could be obtained: Ø Transverse fractures located in the preferred fracture plane and intersecting the wellbore Žrelatively low treating pressure. Ø Gradual fracture reorientation Ø Multiple fractures and stepwise reorientation Žhigh treating pressure.. The existence of this geometry would depend on several factors including the perforated interval, orientation of the wellbore with respect to stresses, and the relative values of stresses.

13. T-shaped fracture As observed earlier, it is easier to create an axial fracture than a transverse fracture. In addition, because of the stress distribution around the edges, fractures would be also created at the both edges of an open hole or a long perforated interval. Consequently, it is feasible to observe this complex Tshaped fracture or even I-beam fractures. This type of fracture will go through a very complex reorientation process. In addition, it will suffer from all the problems listed above in case of multiple fractures.

Fig. 13. Fractured sample HO90 showing inverted T-shaped fracture Žafter Abass, 1995..

Fig. 13 is an experimental example of a T-shaped fracture. To avoid a T-shaped fracture, careful design of the perforated interval and knowledge of stress orientation are necessary ŽAbass, 1995..

14. Pressure relief region During the process of fracturing, the events shown on Fig. 14 take place. The pressure relief event has been recently studied by Abass et al. Ž1992.. During this region, the fluid pressure declines from the breakdown pressure to the fracture extension pressure. The breakdown pressure is a function of the stress field around the wellbore and strength of the rock; and in the cased hole scenario, it is also a function of the perforation friction. The fracture extension pressure is a function of the minimum in situ stress and friction pressure inside the fracture. Abass et al. Ž1992. found a definite relationship between the pressure relief region and horizontal well-orientation angle. The pressure derivative after breakdown plotted vs. orientation angle, Fig. 15 shows a very clear indication of this dependence. This relationship may be used, at least qualitatively, to determine fracture orientation following a treatment or microfracture test. In other words, if the horizontal well was oriented in the direction of maximum horizontal stress Žorientation angle s 0., and an axial fracture was created, it would be expected that the rate of pressure decline would be small. If the

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Fig. 14. Typical pressure profile during a microfrac test.

horizontal well was in the direction of minimum stress Žorientation angle s 90., and a transverse fracture was created, the rate of pressure decline would be high. The relationship between the rate of pressure decline and the orientation angle was found to be semi-logarithmic in nature. This plot could be espe-

cially useful in confirming the orientation of the horizontal well relative to stress orientation.

15. Effect of perforation orientation To maximize the chance of achieving a successful fracturing treatment for a horizontal well, the perforation program should be designed carefully. The designed perforation program should depend on whether the fracture is transverse or longitudinal. Earlier in the text, disadvantages of initiation of non-planar andror complex fractures at the wellbore were discussed. A proper perforation program plays a crucial role in maximization of the chance of getting a single planar fracture that initiates from the wellbore. In horizontal wells, use of one of the following perforation designs is recommended. 15.1. Peripheral perforation

Fig. 15. First derivative of pressure time recorded immediately after breakdown Žfrom Abass et al., 1992..

This perforation scheme is used when a transverse fracture has been designed and the well is drilled in direction of minimum horizontal stress. To avoid the

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creation of multiple fractures, the recommendation is to extensively perforate Ž3608 phasing. a short interval that does not exceed four times the wellbore diameter. In the case of a carbonate formation, it may be helpful to start the fracturing treatment with a stage of HCl acid at a matrix-injection rate to establish a better communication between the wellbore and the fracture.

maximum horizontal stress. In cases where the horizontal well is at an angle other than zero or 908 to the minimum horizontal stress, the situation becomes significantly more complicated. One may conclude from the results presented by Abass et al. Ž1992. that being within 158 from the desired orientation may not be disastrous as long as the perforation program is well designed.

16. Near-well friction

15.2. Axial perforation This perforation scheme is recommended for designs in which a longitudinal fracture is to be initiated. In this design, the high and low sides of the wellbore are perforated Ž1808 phasing.. It may even be preferable to cut slots along the high and low sides of the formation. The above scenario discusses the two extreme cases where the well is drilled either in the direction of minimum horizontal stress or in the direction of

As stated earlier, fracturing a horizontal well requires a very limited perforation interval and may be accompanied by creation of multiple andror tortuous fractures. Since an excessive pressure drop may have a detrimental effect on the progress of the fracturing treatment, it is important to treat this problem. Cleary et al. Ž1993. showed that the near-wellbore friction may be detected by running a variable rate test. ISIP for each rate is determined, and the total pressure drop is calculated. To differentiate between the vari-

Fig. 16. Net pressure vs. injection rate.

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ous factors contributing to the total pressure drop, the data are plotted in accordance with Eq. 15. logD p slog A q Blog q

Ž 15 .

Where: D p s net pressure, or pressure above minimum principal stress; q s injection rate; A, B s constants. The slope of the line, B, indicates the predominant factor contributing to the near-wellbore friction. If B is 2, then insufficient perforation is the major contributor to friction, and more perforations are needed to overcome the problem. If B is between 0.5 and 1.0, the problem is probably due to multiple fracture or tortuous fractures. Injection of slugs of proppant would take care of the problem. Slope of 0.25 is indication of a single fracture and sufficient perforations. Recently, Hyden and Stegent Ž1996. presented a field case for determining the near-wellbore friction as a part of a pre-fracturing test. Their data are given in Fig. 16. The slope of the straight line representing the initial test data is 1.35, indicating very high perforation pressure. When the friction pressure is considered, the lower straight line of Fig. 16 results. The slope of this lower straight line is 0.866. As reported by Hyden and Stegent, this slope indicates the presence of a tortuous fracture. Hyden and Stegent reported that injecting sand slugs successfully eliminated the friction problem.

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from the infinitely conductive horizontal well. Fig. 17 indicates that as the number of fractures increases, and as they get longer, the production through the fractures will eclipse the production from the horizontal well. Giger, on the other hand, indicated that the optimum number of fractures is a function of the length of the transverse fractures. Giger also indicated that based on the steady-state solution, as the number of transverse fractures exceeds four, interference effect between fractures becomes significant, and performance of the system becomes more tied to the length of the fractures ŽFig. 18.. Study of the performance of fractured horizontal wells under unsteady state has been presented in the literature. Soliman et al. Ž1990. discussed the effect of creating multiple fractures intersecting a horizontal well. They also introduced the early time linearradial flow regime that is usually encountered during production of transverse fractures. They also presented the solution for this flow regime. The radial flow regime around the horizontal well would cause a large pressure drop and form a choke to fluid flow. This choking effect will necessitate having high conductivity around the wellbore and may even dictate the use of high concentrationrstronger proppant. On the other hand, Mukherjee and Economides Ž1988. presented a simple correlation to calculate the extrapressure drop due to this choking effect. Mukherjee and Economides presented this pressure drop as an

17. Productivity considerations Productivity of fractured horizontal wells has recently been studied. The earlier work concentrated on the transverse fractures. The goal of most of these studies was actually to study the effect of the presence of natural fractures on productivity of a horizontal well. Using a numerical simulator under steady-state conditions, Giger Ž1985. showed the effect of creating multiple hydraulic fractures. Later, Karcher et al. Ž1986. used a similar simulator to study the effect of naturally existing transverse fractures. They, however, considered the contribution

Fig. 17. Productivity increases of fractured horizontal wells vs. fracture width and number of fractures Žafter Karcher et al., 1986..

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Fig. 18. Fractured horizontal and vertical wells Žafter Giger, 1985..

effective skin factor, Ž Sch .c calculated using the following equation:

Ž Sch . c s

kh kf w

p ln Ž hrr w . y

2

Ž 16 .

The above equation represents the difference between a fractured vertical well and a transverse fracture. One has to remember that this equation is just an approximation. Later, Soliman et al. Ž1989, 1996. presented a procedure of optimizing the number of transverse fractures intersecting a horizontal well. It has been found that the optimum number of fractures would be a strong function of fluid mobility. It was also found that the cost of fracturing relative to the cost of the well would play an important role.

Walker et al. Ž1993. and Soliman et al. Ž1996. studied the contribution of various transverse fractures to the total production of a fractured horizontal well and concluded that the outside fracture contributes more to the total production than the inside fractures. However, for the short-term, this fact did eliminate the need for more than two fractures. Flow regimes encountered after creating transverse hydraulic fractures was best explained by Roberts et al. Ž1991.. In their paper, they described the linear-radial, formation linear, compound linear and finally, pseudo-radial flow regimes. Several authors have discussed the performance of a longitudinally fractured horizontal well. Economides et al. Ž1989. compared the steady-state performance of a horizontal well with a longitudinal fracture to that of a vertical well with a vertical fracture. Fig. 19 shows the results of their findings. The figure

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stress contrast is such that fracture height growth occurs. In this case, neither a fractured vertical well nor a system of transverse fractures will succeed in creating the fracture area achieved by a longitudinal fracture. Whether one chooses to create a longitudinal fracture or a set of transverse fractures depends on factors other than productivity. These may include capability to cleanup the fractures, degree of risk involved in creating each type of fracture, and the cost of fracturing compared to the cost of drilling the horizontal well.

Fig. 19. Productivity index rations of vertical wellrvertical fracture and horizontal well with a longitudinal fracture Žafter Economides et al., 1989..

indicates that for high conductivity fractures, the performance of the two types of fractures is very similar. However, at low fracture conductivity, the horizontal well with a longitudinal fracture would outperform the vertical well with a vertical fracture. The difference between the two increases as the conductivity of the fracture declines. This is basically because in a longitudinal fracture, the fluid has to travel a smaller distance through the fracture, and consequently, this leads to a lower pressure drop. Simulation study of the productivity of transverse and longitudinal fractures has shown that a set of transverse fractures would outperform a longitudinal fracture with equal area in low permeability formations. In the case of tight formations, a high dimensionless fracture conductivity may be achieved, and consequently, the choking effect near the intersection of the wellbore and the fracture is negligible. In the case of higher permeability formations, the advantage of transverse fractures quickly disappears, and a longitudinal fracture may actually outperform a set of transverse fractures. There are some situations where a longitudinal fracture outperforms a set of transverse fractures. One such instance occurs when the formation permeability is high, and a high dimensionless fracture conductivity cannot be achieved. Another situation occurs when the formation is fairly thin and the

18. Field experience Several cases of fracturing horizontal wells have been reported in the literature. In most of them, the operators chose the case of transverse fractures. Problems associated with creating this type of fracture were discussed earlier. In order to avoid creating multiple fractures from a single interval, the perforated interval should not exceed four times the diameter of the wellbore for a transverse fracture. Several authors presented procedures for creating multiple transverse fractures from a horizontal well. The latest and most detailed procedure was presented by Abou Sayed et al. Ž1995.. Earlier, Austin et al. Ž1988. presented an equally interesting procedure in which they suggested the creation of groups of fractures simultaneously. On the other hand, Abou-Sayed et al. suggested creating fractures individually. This approach would ensure better control of fracture initiation and propagation. As discussed by several authors, fracturing horizontal wells will require careful planning during the pre-fracture stage as well as careful monitoring during the fracturing treatment. Chambers et al. Ž1995. presented a fairly thorough discussion of the stimulation requirement and downhole equipment design, as well as the selection criteria for performing the fracturing treatment to create transverse fractures. Their discussion included the use of coiled tubing and selective isolation systems. The drilling and stimulation of a horizontal well in a naturally fractured formation requires careful attention to detail in planning. The orientation of the natural fractures with respect to the induced

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hydraulic fracture will significantly affect the progress and outcome of the hydraulic fracturing treatment. In most cases, a horizontal well will be drilled in a direction that is perpendicular to the natural fractures. In the case where the natural fractures are randomly oriented, the hydraulic fracture treatment should be designed to increase the probability of encountering the bulk of the fractures. Under such conditions, the principal stress orientation and magnitude should be determined and should dictate the direction of the well. Consideration should be given to how the natural fractures will affect the propagation of the induced fractureŽs.. A study conducted by Overbey et al. Ž1988. demonstrated that multiple-oriented, multiple hydraulic fractures can be induced from a horizontal wellbore under open hole conditions where the natural and induced fracture orientations were "158. Studies by Layne and Siriwardane. Ž1988. and Yost et al. Ž1988. have yielded similar results. Recently, longitudinal fracturing has gained more acceptance. This may be due to several factors, including the ease of creating this type of fracture, its ease of cleanup, and the possibility of creating this type of fracture in an open hole environment. In this approach, the cost of cementing and casing are saved, and this saving may be attractive in the situation in which the cost of cementing and casing is a considerable portion of the cost of the well. These scenarios can include onshore wells through shallow formations. In such cases, it may be logical to trade some loss of control, certainty, and the involved extra risk for the cost saving.

19. Nomenclature A, B CfD d h k kf w l, m l m

Constants Dimensionless fracture conductivity, k f wrkl f Wellbore diameter Žm. Formation thickness Permeability Fracture conductivity Directional parameters of the wellbore from the in situ stress field in Eq. 14 ŽcosŽ u .. 2 ŽsinŽ u .. 2

l Lf L L1 L2 pb q r rw w lrwt w a A b

sr , su , sz sh sH sv su sc Dp n u

Perforated interval Fracture half-length Horizontal well length Fracture length along the wellbore Fracture length normal to minimum stress Breakdown pressure Injection rate Ratio between intermediate and minimum principal stresses Wellbore radius Žin.. Reduction in fracture width Fracture width Biot’s constant Wellbore deviation from the vertical Angle between direction of horizontal borehole and minimum horizontal stress Effective stresses at wellbore Minimum principal horizontal stress Maximum principal horizontal stress Vertical stress Tangential, or hoop stress Compressive strength of formation rock Change in pressure or net pressure Poisson’s ratio The position of the measurement of the tangential stress around the circumference of the wellbore

Acknowledgements The authors of this paper wish to thank the management of Halliburton Energy Services for permission to prepare and publish this paper. Thanks are also due to Nancy Woods and Sam Moore for their help in preparing the manuscript of this paper.

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