Fracture Treatment Optimization for Horizontal Well Completion M.Y. Soliman, Reinhard Pongratz, Halliburton; Martin Rylance, TNK-BP; and Dean Prather, Halliburton
Copyright 2006, Society of Petroleum Engineers parameters influencing the completion of a well. Fluid flow and This paper was prepared for presentation at the 2006 SPE Russian Oil and Gas Technical geomechanical aspects of fracturing a well cannot be ignored Conference and Exhibition held in Moscow, Russia, 3–6 October 2006. when multiple fractures are created. This is especially true in This paper was selected for presentation by an SPE Program Committee following review of case of fracturing horizontal wells. information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to Although unstimulated horizontal wells have been very correction by the author(s). The material, as presented, does not necessarily reflect any position successful in naturally fractured reservoirs and in reservoirs with of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum gas- or water-coning problems, there are many situations where Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. fracturing a horizontal well to improve production capability is a Permission to reproduce in print is restricted to an abstract of not more than viable or necessary option. The orientation of a hydraulic 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box fracture, with respect to the wellbore, is directly related to the 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435. wellbore azimuth with respect to the in-situ stress field. Therefore, the possibility of fracturing a horizontal well must be Abstract considered before the well is drilled. The appropriate Fracturing has become a viable and important option for contingency plans should be made to anticipate the possibility of completing horizontal wells. There are many fracturing low productivity from an unstimulated well. processes and methods to consider for placement fractures. It should also be remembered that fracturing a horizontal Optimization of the completion process including the number well may dictate which direction the well should be drilled and and size of fractures is still a challenge. how it should be completed. Fracturing a horizontal well does Although fundamentally similar to fracturing vertical wells, not necessarily mean that the well has to be cased and cemented. horizontal well fracturing has unique aspects that require special There are many cases of fracturing horizontal wells in openhole attention to ensure successful treatment. Differences exist or uncemented liners. The field example within this paper between horizontal and vertical wells in the areas of rock discusses one of these cases. Fracturing a horizontal well may be mechanics, reservoir engineering, and operations. These aspects considered when one of the following situations is apparent. affect the optimization process for successful placement of ， Restricted vertical flow caused by low vertical treatments and optimum asset performance. permeability or lamination. In this paper we discuss the various factors crucial to ， Low formation productivity because of low formation successful completion of a fractured horizontal well. We discuss permeability. these factors in relation to both longitudinal and transverse
， Low-stress contrast between the pay zone and the fracture applications. Success factors include the optimum
surrounding layers. In this case, a large fracturing perforation process, overcoming fluid flow convergence towards
treatment of a vertical well would not be an acceptable the wellbore in case of a transverse fracture, and the fluid flow
option because the fracture would grow in height as well as and stress interference between multiple fractures.
length. The paper presents a field case and laboratory and numerical experimentations illustrating the impact of the various factors on
The effects of lamination within a reservoir body are not the completion of the horizontal wells and the optimization of
generally considered, or their importance underestimated when the fracturing process.
designing horizontal well completions. The presence of laminations is considered to be one of the principal reasons Introduction
behind poor performance of a number of horizontal wells. A Fracturing is no longer restricted to vertical wells drilled in hard
significant percentage of moderate- and low-permeability formations with very-low permeability. Higher permeability,
formations are laminated with low-permeability streaks that softer formations as wells as horizontal wells are now routinely
result in a low effective vertical permeability. Even a very thin fractured. This has led to the importance of examining all
barrier that may be too thin to readily detect can form a barrier reservoir aspects to reach a better understanding of efficient
that essentially prevents hydraulic communication between the fracture design and eventually the optimization of the well
horizontal well and the formation beyond this barrier. In these completion. This should include the theoretical and operational
cases the creation of a number of vertical transverse or
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longitudinal fractures would allow the effective drainage of the transverse fracture to be less effective than a fracture reservoir through these fractures. intersecting a vertical well. The two flow regimes are identical Although fundamentally similar to fracturing vertical wells, for infinite conductivity fractures. This indicates that transverse fracturing horizontal wells has unique aspects that require fractures may not be recommended for higher-permeability special attention if the most successful treatment is to be formations unless severe formation damage is expected around secured. Differences between horizontal and vertical wells exist the wellbore and the fracture is merely designed as a means to in the areas of fluid flow, rock mechanics, perforation strategy, connect the wellbore to the undamaged formation. The problem and operational procedures. It has already been well established with this convergence of fluid is increased because of the non- that the two extreme fracture orientation cases are transverse and Darcy effects in the fracture that would be expected in the case longitudinal fractures. The various aspects of fracturing of higher production rates.
horizontal wells for both transverse and longitudinal fractures Because high pressure drop is expected because of the fluid- are examined in the next few sections as pertaining to flow convergence that occurs around the entry to the transverse optimization-fractured horizontal wells. fracture, tailing in the pumping stages of a hydraulic fracturing
operation with a high conductivity “tail-in” proppant would be
recommended. Hydrajetting the wellbore before fracturing and Fluid Flow Aspects of Fractured Horizontal Wells
The most significant advantage of this approach is the creation packing the fracture during the later stages of fracturing with a of multiple parallel fractures resulting in an acceleration of larger and/or stronger proppant is highly recommended. hydrocarbon production. The creation of multiple fractures Because the radial-linear solution is valid only at early time, allows an efficient drainage of the reservoir with fairly small several authors10-13 have expanded their investigations to study
the flow regimes in the reservoir at a later time. Roberts, et al10 fractures. To reach the same effect by drilling a vertical well
would require a significantly longer fracture that would also presented a description of the expected flow regimes linear-
radial, formation-linear, compound linear, and finally, pseudo- have a greater height. This would increase the chance of
fracturing through a gas cap or water aquifer. The inclusion of radial flow regimes. These flow regimes are illustrated in Fig. 1.
unwanted gas or water production, as well as fracture A transition period is expected between the various flow
regimes. Some of these flow regimes may not be apparent, communication with a fault boundary, would negatively affect
production. depending on reservoir extent, continuity, and geometry. The increased productivity caused by the presence of
transverse fractures has been studied by many authors.1-16 An early work in this area was presented by Karcher, et al.1 Giger2 used a numerical model to study the steady-state production increase from a horizontal well with multiple, infinite conductivity vertical fractures. Work by Giger indicated 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 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, the interference effect between fractures becomes significant, and performance of the system become more tied to the length of the fractures. 10 Fig. 1―Potential flow regime in a fractured horizontal well. Flow Regimes in a Fractured Horizontal Well—Transverse
The numerical simulation of fluid flow around a fractured Fracture
horizontal well, with no additional wellbore contribution, readily The early-time flow regime around a transverse fracture has
matches the flow regimes that have been predicted analytically. some similarity to that occurring in the case of a fractured
At early-time these numerical simulations demonstrate the vertical well. Because the wellbore intersects the fracture in the
expected elliptical flow regime around each of the individual center, the flow regime may initially be approximated by radial
fractures. Then at an intermediate-time they reflect the flow, followed by linear-radial flow.3 The linear radial flow
interference between the various fractures. Finally, at late-time period corresponds to the bi-linear flow regime observed when
they readily describe the elliptical flow regime around the entire fracturing a vertical well. Because multiple fractures are usually
fractured area, as well as the continued strong interference created, this linear-radial flow period ends when interference
between the individual fractures. from the surrounding fractures is observed.
When the wellbore is allowed to contribute to production, by It can be seen that the fluid in the fracture for a horizontal
either fracturing openhole or by performing perforating well must converge radially toward the wellbore and as a result,
operations, there will be some impact on the well productivity an additional pressure drop must be considered in predicting the
and on the flow regimes. It is apparent that the overalloverall production performance. This effect will cause a single
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magnitude of this production effect will depend on the reservoir
and fluid properties, however, as Figs. 2a–2c demonstrate, the
contribution of the wellbore will decline fairly quickly with
time. It should be noted however, that there will be an expected
deviation from the ideal flow regime as described in Fig. 1.
The vertical permeability has a very strong effect on the
contribution of the unfractured part of the horizontal well. In
tighter formations with low vertical permeability, almost all
production will be flowing to the well via the fractures.
Fig. 1 corresponds to fracturing a horizontal well that has
been cased and cemented prior to fracturing, while Fig. 2 is
equivalent to creating hydraulic fractures in an open hole using
techniques such as hydrajet-assisted fracturing.
Fig. 2c—Simulated pressure distribution after 5,000 days of production. Flow Regimes in a Fractured Horizontal Well—Longitudinal
The performance of longitudinal fractures may be compared to
that of fractured vertical wells and transverse fractures. This
comparison depends on the dimensionless fracture conductivity,
vertical permeability of the formation, and the fracture aspect
ratio. Aspect ratio of the fracture is defined as the ratio of
fracture length (tip to tip) to height.
When the fracture conductivity is infinite or almost infinite,
the fluid flow in the reservoir towards the longitudinal fracture
will be in the horizontal plane only. In other words, the vertical
permeability would not have any effect on the flow regime. In Fig. 2a—Simulated pressure distribution around individual fracs in early- this case, the flow regime would be directly comparable to the time. flow regimes for a vertical well intersecting an infinitely conductive vertical fracture.
However, if the dimensionless fracture conductivity is low, the fluid may tend to move a greater distance in the formation towards the wellbore. In such a case, the vertical permeability would directly affect the fluid flow. Therefore, in this case, the behavior for a horizontal well intersecting a longitudinal fracture would be different from a vertical well intersecting a vertical fracture. In addition, it is intuitive that the distance the fluid moves within the longitudinal fracture is somewhat less than in a vertical well intersecting a fracture with similar dimensions. Economides, et al.15 compared the steady-state performance of a horizontal well with a longitudinal fracture to that of a vertical well with a vertical fracture. Fig. 3 shows the principal results of their findings. The figure 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 case of a Fig. 2b—Simulated pressure distribution after 461 days of production. longitudinal fracture, the fluid has to travel a shorter distance
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through the fracture, and consequently, leads to a lower pressure fluid approaches the wellbore. As has been reported by Soliman, drop. et al.3 the effect of convergence becomes more severe as the
dimensionless fracture conductivity declines.
Fig. 4—Comparison of longitudinal fracture vs. fractured vertical well.
Fig. 3—Effect of aspect ratio and dimensionless conductivity on the productivity of a longitudinal fracture relative to a fractured vertical well.
Production Comparison from Different Well Types
Experimentations with a numerical simulator for transverse,
longitudinal, and fractured vertical wells have been performed
and the results are presented in Fig. 4. In this case the total
fracture area (height-length product of the fracture) is the same
for each fracturing scheme. The aspect ratio for the longitudinal
and fractured vertical well is 3.3. The figure shows the clear
superiority of a longitudinal fracture over a fractured vertical
well when the fracture conductivity becomes low. At high
dimensionless-fracture conductivity the two scenarios are comparable. This means that in case of a tight, thick formation Fig. 5—Comparison of longitudinal fracture vs. transvers fractured where the aspect ratio is not much larger than 1 and achieving a horizontal well. high dimensionless conductivity is relatively easy, a longitudinal or fractured vertical well with the same fracture dimensions To address this convergence phenomenon, it is suggested to would be competitive. However, in the case where formation maintain high fracture conductivity near the mouth of the permeability is mid-range, 1-5 md, where the dimensionless fracture. This may be achieved by tailing in the fracturing conductivity would be relatively low, it would be preferable to treatment with larger and or stronger proppant. Additional create a longitudinal fracture. Similarly, if the formation is fairly methods to enhance fracture/wellbore communication include thin, potentially leading to a large aspect ratio, a longitudinal initiating the fracture by jetting the wellbore or designing a tip fracture would also outperform a fractured vertical well. screenout and packing the frac to increase the frac width at the Operationally, creating longitudinal fractures using several wellbore. stages is more achievable than creating a long fracture in a Fig. 5 also includes a case that demonstrates the influence of vertical located in a thin formation. achieving a high dimensionless fracture conductivity for just a The performance of transverse fractures is, however, 10-ft radius from the wellbore. The observed tremendous considerably superior to the performance of either longitudinal increase in well productivity/deliverability leaves no doubt or fractured vertical well in the case of high dimensionless regarding the importance in achieving and maintaining conductivity fractures. This is illustrated in Fig. 5. When the conductivity in the near-wellbore regions when designing these fracture dimensionless conductivity is low, the performance of a treatments. longitudinal fracture would be comparable to that of transverse fractures. However, transverse fractures can provide potential Effect of Non-Darcy Flow advantages vs. longitudinal fractures even at low dimensionless Usually fluid flow through porous medium or through the conductivities, in late-time performance. This advantage is fracture is assumed to be laminar. In this case, the Darcy related to the convergence of fluid within the fractures as the equation describes the pressure gradient in terms of rate and
SPE 102616 5
reservoir properties. 3 pb；？；， l；;， L；;， c ...............................(4) 2 ！ p；( v ？ .............................................(1) ！ L k where；， L is the largest of；， v and；， H and；， l is the smaller of the two. Usually the assumption of laminar flow in the reservoir is a
valid assumption. The exception would be high rate gas wells. ， c is the compressive strength of the rock. The non-Darcy flow may occur in either the formation or the This failure criterion was applied to laboratory experiments fracture. The non-Darcy flow may be expressed in the following for fractured horizontal wells with a reasonable success. Table 1 non-linear form:17 gives a comparison of observed versus calculated breakdown
pressure for a transverse fracture. Please note that each row of ！ p ( v ？；？；，；； v 2 ...............................(2) the table represents several experiments. ！ L k
Table 1—Comparison of Breakdown Pressure Calculation to In this case the pressure drop caused by fluid flow will be Observed Laboratory Data higher than in the case of laminar flow. The Beta factor is a Calculated Calculated function of reservoir permeability and porosity. Usually Beta Observed Experiment Pressure Using Pressure Using factor for fluid flow inside the fracture depends on the proppant 21 Pressure, 21 H&W Criterion, H&B Criterion, size. Correlations exist for calculating the beta factor for ceramic Group psi psi psi and non-ceramic proppant. Similar correlations exist for HZ-1 2,850–3,850 1,750 3,275 calculating the beta factor inside the reservoir. Smith, et al.18 recently presented a detailed investigation of effect of non-Darcy HX-2 3,400–4,250 1,750 3,600
flow on well performance. Table 1 clearly demonstrates that the Hoek and Brown Geomechanics Consideration of Fracturing Horizontal failure criterion gives a significantly better estimate than Wells Hubbert and Willis of the breakdown pressure necessary to Three different aspects of fracturing in horizontal wells are create a transverse fracture. The Hubbert and Willis failure discussed in this section; breakdown pressure, depletion effects, criterion calculation is an indication of the breakdown pressure and stress interference of multiple transverse or longitudinal necessary to create an axial fracture. Table 1 indicates that under fractures. the same stress field, it is easier to create an axial fracture than a
transverse fracture. Fracturing Breakdown—Transverse Fractures Owens, et al.26 presented another approach for calculating The Hubert and Willis19 failure criterion is commonly used to the breakdown pressure of an arbitrarily oriented horizontal predict the breakdown pressure of a vertical well. In vertical well. In his approach, Owens, et al. applied the equations wells, fractures are usually axial, and consequently, the failure developed by Daneshy27 to calculate fracture initiation pressure. criterion occurs when the tangential pressure is less than zero. In They compared their calculated values to observed field data other words, the tensile breakdown pressure for a vertical well from a North Sea field, Fig. 6. under this failure criterion is given by the following equation. pb；？ 3， h；;， H .......................................(3) This failure criterion may be used in case of longitudinal fractures to determine the breakdown pressure. However it has been observed in the laboratory20,21 and in the field21 that Hubert and Willis failure criterion may significantly underestimate the breakdown pressure for a transverse fracture. This is basically because this failure criterion assumes the creation of an axial fracture. Weijers, et al.22 could not correlate the fracture initiation pressure and the tensile failure solution. The Hubert and Willis failure criterion is valid for a vertical well or a horizontal well where the fracture is longitudinal, however it does not fit a situation in which the fracture is transverse. The Hoek and Brown23,24 failure criterion was applied to fracturing a horizontal well25 (creating a transverse fracture). Fig. 6—Fracturing pressures from arbitrarily oriented horizontal wells in a 26 The breakdown pressure under this failure criterion is given in North Sea chalk formation (after Owens, et al. ). the following equation:
One technique that has been successfully applied in
cemented and cased horizontal wells requires drilling the well in
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the direction of minimum stress, and then perforating very short being injected, through both the annulus and tubing, to move
intervals. This interval should not be more than four times the into the fracture plane. This is essentially the basic principle
openhole diameter of the wellbore. Fig. 7,20 which clearly behind the jet pump. Also, the mixing of high velocity fluid
demonstrates that as long as the perforated interval is short a coming from the jet with the low-velocity fluid coming from the
planar fracture is created that is transverse to the well. If the annulus causes the pressure inside the hydrajetted tunnel to
perforated is longer than four times the diameter of the well, increase. The basic fluid mechanics equation for this principle is
then we would expect to see a complex, non-planar fracture, known as Bernoulli‟s equation.
such as in Fig. 8.28
Fig. 9—Effect of completion type on creating a longitudinal fracture.
Fracturing Breakdown—Longitudinal Fractures
To create longitudinal (axial) fractures, the well has to be drilled perpendicular to the minimum horizontal stress. The most Fig. 7—Effect of length of perforated interval on the creation of a commonplace completion technique chosen is to conventionally transverse fracture. case and cement the well, then perforate short sections in the vertical plane. Subsequently, sections of the well are isolated and fractured in the same way. The length of the perforated sections depends on the mechanical and physical homogeneity of the formation and on the degree of control that one may want to exercise over creating the longitudinal fractures. Since the longer the fracture, the higher the injection rate needed, injection rate may be one of the controlling factors. Creating elongated slots or hydrajetting in the upper and/or lower sides of the well could very well replace the perforation process, and would lead to lower breakdown pressure. The shorter the isolated area, the more control one has over
the created fracture. However, if the formation is fairly homogeneous, a longer section may be fractured without compromising this control. The extreme case is to fracture the Fig. 8—Fractured block sample showing inverted T-shaped fracture. total length of the horizontal well in one stage under openhole
completion conditions. Such a scenario was implemented in Another technique that has been developed for particular 33 several wells successfully.application in open hole relies on the use of hydrajetting. Hydrajetting the borehole wall creates a clean, fairly large, and Pressure Depletion Effects continuous path into the formation.29-32 Additionally, As the pressure inside the reservoir and fracture declines, the hydrajetting creates a clean path away from the wellbore, thus reservoir permeability, porosity, and the fracture conductivity reducing the breakdown pressure necessary to initiate the may decline. This process is generally not reversible, although transverse fracture. In an experiment to study the effect of undergoing hysteresis. The nature of the hysteresis depends on notching, which is similar but not identical to hydrajetting, on the particular formation rock properties. To study the effect of the creation of a longitudinal fracture, it was found that a the change of the reservoir permeability as a function of stress, notched well could be fractured at a lower pressure than either we applied the approach developed by Settari34 into the an openhole or perforated formation. Fig. 9 shows the set up of simulator used in this study.the experiments. Once the fracture is initiated, the hydrajetting
process uses basic fluid mechanics principles to cause the fluid
SPE 102616 7 fractures are created from a single well. Soliman38 studied this Fig. 10 shows the change in pressure as function of the total
production for two cases. All the reservoir parameters are the effect using Sneddon‟s solution for both a semi-infinite35 and
same except for considering the effect of changing permeability Penny shaped36 fractures. The presence of cased hole versus
as reservoir pressure declines. The figure clearly indicates that open-hole completion could also make a difference.
ignoring the effect of geomechanics will have an effect on the In fracturing horizontal wells with multiple transverse
long-term production. Fig. 11 shows that the difference in fractures it is important to understand the effect that stress
cumulative production is only 6%, however this translates with interference may have on fracture behavior. Because of the
current oil prices of $70/bbl to over estimation of revenue by creation of multiple propped fractures, it is expected that the
more than $3,000,000. stress interference will increase as the number of fractures
increases. Fig. 12 indicates that if the distances between the transverse fractures are equal to the fracture diameter; dimensionless distance between fractures is equal to 1, then while creating the fourth fracture it would expected that the net pressure would increase by 21% above the net pressure encountered during the
creation of the first fracture. The net pressure is defined as the
fracturing pressure above closure pressure. This increase in pressure may not be alarming, however if the distance between the fractures is half that of the diameter of the fractures then the net pressure expected during the creation of the fourth fracture is almost twice that encountered during the creation of the first fracture. The net pressure significantly increases in later stages as shown in Fig. 12.
The interference between fractures causes all stresses to change, and the minimum horizontal stress (perpendicular to the Fig. 10—Effect of stress sensitive formation on well productivity. fracture) increases by a larger degree than the other two.
Actually the stresses parallel to the fracture will slightly decline at a distance larger than 0.4 of the fracture diameter. This will cause the stress contrast to change (decline) as more fractures are created. If at any point the stress changes by a value larger than the original contrast, it would be expected that the preferred fracturing orientation near the wellbore may also change. If not accounted for, this could be problematic. The situation is even more critical when openhole fracturing such as hydrajet-assisted fracturing29-31 is practiced. Fig. 11 shows the potential change in stress contrast caused by creation of multiple fractures. This figure indicates that if the distances between the transverse fractures are equal and equal to the fracture diameter, then while creating the fourth fracture it would expected that the change of stress contrast would be about 24% of the net pressure
encountered during the creation of the first fracture. If the distance between the fractures is half that of the diameter of the Fig. 11—Change of stress contrast as a function of number of transverse fractures then the change in the stress contrast expected during fractures and distance. the creating the third fracture is a little more than the net pressure encountered during the creation of the first fracture. In The effect would become more significant if the hysteresis other words the stress contrast has changed by an amount about effect on reduction of permeability and porosity is considered twice the net pressure encountered during the creation of the first and the well had gone through several cycles of production and fracture. shut-in. Change in stress orientation near the wellbore does not mean change away from the wellbore. This indicates that the change in Stress Interference Between Fractures the stress field near the wellbore may be reversed causing the The creation of a hydraulic fracture can readily alter the stress creation of a longitudinal instead of a transverse fracture. field within its immediate vicinity35-36 and thus potentially affect However away from the wellbore the stress field may revert the orientation of other hydraulic fractures created from nearby back to its original condition. This would cause the fracture to wells. Sneddon‟s solution for a semi-infinite fracture38 was used reorient itself again in space. This again may cause severe by Warpinski and Branagan37 to study the alteration of stress tortousity and potentially sanding out of the fracture.around a fracture. The effect may be more significant if multiple
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Fig. 13 is a Barnett Shale horizontal well with uncemented Optimization of the number of transverse fractures
casing that was treated with 12 hydrajet waterfrac treatments in To optimize the number of fractures intersecting a horizontal
one day. The graph clearly demonstrates increasing stress well, the fluid flow and geomechanics aspects that have been
interference between the fractures from the first frac through the discussed need to be applied. As we have seen, increasing the
12th frac.. Based on this evidence, it would appear that highly- number of fractures intersecting a well will increase the total
fractured formations have the capacity to absorb stresses created production from the fractured well; however the rate per fracture
by the growth of hydraulically induced fractures while reservoirs will decline because of their interference.
with little natural fracturing would have substantial treating Stress interference between the fractures and its potential
pressure issues when creating multiple fractures using the effect on the stress values and even the orientation of the
hydrajet-fracturing process. In Fig. 13 the change in ISIP intended fracture may dictate the distances between fractures to
represent a change in the closure pressure or in other words minimize or eliminate potential operational problems. However,
change in the minimum stress. the number of fractures would be determined based primarily on
an economic analysis that considers the economic parameters for a specific set of conditions. This parameter may include net present value (NPV), ROI, ROE, etc. The risk factor involved in creating multiple fractures may be incorporated into the system by using an optimization parameter such as benefit-cost ratio.5
Operational Aspects of Fracturing Horizontal Wells The most important factor in ensuring that a single fracture is initiated in a horizontal well is to apply focused energy during the initiation process. There are a number of different ways in which this can be achieved, and these are discussed for various completion types within this section. Openhole Completions When working in an openhole scenario, the principle requirement is to initiate and propagate the fracture in the
desired location to ensure optimum productivity. The stresses Fig. 12—Change of fracturing net pressure as a function of number of along the wellbore and friction of the fluid being pumped down transverse fractures and distance between them. the wellbore will affect where the fracture initiates and may or
may not give us a desirable outcome.
Methods that can be used to help ensure success include:
， Hydraulically perforating or notching the openhole
formation with a hydrajetting tool.
Using a propellant or perforating to initiate a fracture in ，；
the open hole.
Mechanically isolating a short section of open hole and ，；
treating only this interval.
Of these techniques, the most consistently successful approach has been the hydrajetting of the formation for Fig. 13—ISIPs for 12 consecutive Barnett shale hydrajet water fracs perforating and fracture initiation. Mechanical isolation of the placed in a horizontal well in one day. formation has also been widely applied with perforating, sliding-
sleeves, and acid-soluble ports; however, retained isolation has Effect of Different Types of Completion of Horizontal Wells proven evasive as shown by micro-seismic mapping and gauge on Stress Interference data. Regardless of the type of completion, the effect of stress interference will exist. However in openhole fracturing such as Open Hole with Slotted Liner in hydrajet-assisted fracturing the effect may be more In an openhole scenario there are more potential candidates, with pronounced. This is because of two factors. The first is the few delivering the consistent results that are expected. One of capability of fluid to enter the fractures previously opened the first applications was the use of preperforated liner and high thereby raising the pressure in the fracture to a new level. The rate, commonly referred to as a sprinkler system. The thought second factor is that if the change in stress contrast is large was to use the perforations as a way to evenly distribute the enough, longitudinal and/or non-planar fractures may initiate, treatment as seen in the top picture. Monitoring of the fracturing which may cause an early and unplanned sand-out. process indicated that the fractures concentrated near the heel
SPE 102616 9
and toe of the horizontal well. Results were at best marginal and fracture generation. This has allowed consistent focused energy inconsistent. to effectively fracture treat the reservoir.
In these cases perforated with conventional methods, acid- In summary, the decision to drill a horizontal well is a soluble ports, or a sliding sleeve (mechanical or ball-operated) completion technique, not a drilling process. The decision of have been used. However these techniques have shown a low what type of completion technique to apply should include the success rate of isolation as has been demonstrated by pressure completion engineer at the beginning of the planning process. To gauges and microsiesmic mapping. Even if successful isolation be successful the completion engineer must select the occurs, the fracturing energy is spread out across the entire stimulation process that delivers energy focused to initiate the openhole section leading to difficult fracture generation, and no fracture. Energy dispersed over a large interval when trying to predictability in placement, leading to higher failure rates in create a fracture will lead to inconsistent fracture geometry and placing proppant. less than optimum results. The thought process must be centered Another option to leaving the open hole fully exposed is on focused energy to initiate a single fracture. hydrajetting the holes in the pipe and initiating a fracture with
the hydrajet tool. This has a chance of providing the focused Horizontal Well Fracturing—Field Case
energy needed to initiate a fracture where you are cutting. The following data summarizes the application of multiple The last option for this scenario is the use of a chemical fracturing in a horizontal well (Well A) as a remedial completion packer for isolation of the annulus. Once again, perforated technique within a poorly performing existing completion; as conventionally using acid-soluble ports or a sliding sleeve such, the completion type was not chosen to assist the multiple (mechanical or ball-operated). The high extrusion pressure will fracturing scenario.
allow effective energy focus, once the hole is in the pipe, to Fracture design was investigated for the well and three successfully allow the focused fracture generation. If required to transverse fractures were planned with roughly equal spacing do an openhole cased completion, one of these last two options along the horizontal section. The well had been originally or combination of them would be preferred. completed with an uncemented slotted liner. Because this could The cased and cemented option can include two options, not be altered, it was decided to apply the hydrajetting technique cementing with conventional cement or acid-soluble cement. to maximize the efficiency of the fracture-to-wellbore When cementing with conventional cement, it is well known that communication.
a high net pressure is required to maintain the fracture For each of the fracturing treatments the following stages generation as documented by Garces, et al.39 and acid-soluble were performed.
cement has clearly demonstrated success in minimizing entry 1. Circulation and hydrajet perforating or notching of the friction and improving completion success.40-41 liner at measured depth. Performing a minifrac (closure pressure and fluid 2.
efficiency). Perform a hydrajet-assisted fracturing treatment at the 3.
desired measured depth.
A schematic of the treated well is provided in Fig. 15.
Circulation and Jetting
During the first stage the well was circulated using 35-lb linear
gel at 0.8 m3/min with a total of 36 m3 fluid, this stage confirmed
that all three jets were open. After the perforations had been
jetted for 7 min, the annulus valve was closed to achieve a breakdown of the formation. The annulus pressure increased Fig. 14a—Conventional Fig. 14b—Acid-soluble cement is rapidly from 18 to 94 bar, and annulus pumping was then cement leads to high entry washed away by acid from removing initiated to achieve a fracturing rate and preparations was made friction. the tortuous path. to perform the minifrac.
If conventional cement is run, hydrajet perforating is Minifrac Operations recommended to prevent the near-wellbore entry problems. Fig. 16 shows the rate and pressure that were observed during If acid-soluble cement is run, conventional perforating, the minifrac test and Fig. 17 shows the diagnostic plot of the sliding sleeves (mechanical and ball-operated), or hydrajetting minifrac data indicating that the fracture encountered some are all acceptable ways of achieving holes in the pipe. In each height recession, which is attributable to penetration into a case any fracture treatment should be preceded with a volume of higher-stress formation. acid to remove the acid-soluble cement from around the The minifrac analysis indicated that the surface ISIP was 95 perforations. When using this type of cementing process, the bar. Taking into account the hydrostatic column, the bottomhole results have consistently demonstrated predictable and focused ISIP was estimated to be 376 bar. From the minifrac analysis the
bottomhole closure pressure was calculated at 289 bar, yielding
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a closure gradient of 0.126 bar/m. Fluid efficiency was
calculated to be 47% while the reservoir pressure was estimated
to be 231 bar.
Fig. 17—Minifrac analysis diagnostic summary.
Main Frac Operations
During the early stages of the main fracturing treatment, a steady
net pressure increase was observed at surface. This is reflected
in the annulus pressure, which increased from 108 to 128 bar
over this period.
Midway into the treatment a sudden pressure spike from 306
to 462 bar on the tubing side was observed, however there was
no change on the annulus pressure. This was readily
interpretable as one of the jets becoming blocked. This was
confirmed when the jetting tool was recovered and metal debris
was found lodged in one jet.
To continue, the tubing pump rate was reduced such that the
maximum pressure limits were not exceeded. The post-frac ISIP
was 120 bar, which indicated a permanent net pressure increase
of 25 bar. Fig. 18 is a summary of the pumping operations for
the first treatment, subsequent treatments were uneventful.
Fig. 15—Well A1 schematic of the wellbore indicating individual frac locations.
Fig. 18—First fracturing treatment rate and pressure plot.
From the above field case, it can be concluded that:
The frac treatment was pumped and displaced ，；
completely, indicating that this technology can be applied as a remedial technique for fracturing horizontal Fig. 16—Minifrac test rate and pressure plot. wells in this field.
No significant annulus response was encountered during ，；
the cutting stages of the operations and the formation
was efficiently broken down without problems.