SPE Copyright 2007, Society of Petroleum Engineers

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1 SPE Better Reservoir Manageent Through Iproved Water Injection Methods With Data Analysis and Detailed Fracture/Reservoir Modeling Håvard Jøranson, Statoil, SPE, Henry H. Klein, H K Technologies, SPE, Arne M. Raaen, Statoil, SPE, Michael B. Sith, NSI Inc., SPE Copyright 2007, Society of Petroleu Engineers This paper was prepared for presentation at the 2007 SPE Annual Technical Conference and Exhibition held in Anahei, California, U.S.A., Noveber This paper was selected for presentation by an SPE Progra Coittee following review of inforation contained in an abstract subitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleu Engineers and are subject to correction by the author(s). The aterial, as presented, does not necessarily reflect any position of the Society of Petroleu Engineers, its officers, or ebers. Papers presented at SPE eetings are subject to publication review by Editorial Coittees of the Society of Petroleu Engineers. Electronic reproduction, distribution, or storage of any part of this paper for coercial purposes without the written consent of the Society of Petroleu Engineers is prohibited. Perission to reproduce in print is restricted to an abstract of not ore than 300 words; illustrations ay not be copied. The abstract ust contain conspicuous acknowledgent of where and by who the paper was presented. Write Librarian, SPE, P.O. Box , Richardson, Texas U.S.A., fax Abstract The search for practical engineering tools to better anage water injectors has been ongoing for any years. Siple analytical solutions have proven inadequate, and ost reservoir siulators do not explicitly odel water injectors. This paper proposes a ethodology of using detailed and coupled fracture and reservoir odeling to ensure proper injection start-up procedures, and anaging injection rates to avoid outof-zone injection. This is cobined with siple rate-pressure data to understand injection behavior, and fro that control the process. Introduction Water injection, in particular produced water injection, in ost cases creates a fracture. As is well established [1], teperature effects are iportant, because the cold injection fluid reduces the teperature of the near well forations, leading to a reduced iniu in situ stress. If the fracture reains within the cooled region, the reduced stress ay be a significant factor in reducing fracture height growth, or in other words, for the confineent of the fracture to a given foration. As a result, siulations of water injection need to take fracturing and the teperature effects on fracturing into account. In this paper we briefly review soe eleentary aspects of the response of a fractured injector. We proceed to show field exaples of fracture growth, with particular ephasize on its episodic nature. Next, we describe a new odel for the siulation of water injection, which includes theral effects and plugging due to dirty injection water. The ain part of the paper is a discussion of soe siulations, focusing in particular on how the rate schedule of injection start-up ay be used to influence the height growth of the fracture. This is of central relevance for any field cases, where it ay be iperative to constrain fracture height growth, e.g. to avoid growing into a thief zone. In ters of reserve recovery, this is crucial. If the fracture grows into high pereability layers, those layers begin to accept ore injection. This causes preferential cooling in those zones, reducing closure stress there. The fracture then igrates there, further increasing injection into that zone, causing ore cooling, etc., etc. Ultiately, this causes early water breakthrough and lost reserves! Basic injector perforance With odern data acquisition systes, extensive datasets are norally available for all or any of the injectors in a field. Hence it is iportant to find an effective way of screening the data, in order to single out the features for further study. A plot of large aounts of data in a pressure versus rate plot ay be an effective ethod, in particular if color coding is used to separate different tie intervals. Before showing real data, we briefly recap the ain features of injector response in the pressure versus rate doain. Fig. 1 scheatically shows the response of an injector working both in the atrix and fracture regies. The full line describes an initial situation, in which the injector injects into atrix up to a given pressure where the fracture opens, and an increased injectivity results. The dashed line shows the change resulting fro a stress reduction due to reservoir cooling. To a first approxiation the slopes of the atrix and fracture injection lines are unchanged, but the intercept takes place at a lower pressure due to the reduced reservoir stress. The dash-dot lines show the effect of pressure build-up around the injector. This affects both the atrix injection and the fracture injection. Note how the intercept occurs at a lower injection rate. This is because the atrix injection responds directly to the pressure, while the initiation of fracture injection responds to the changes in the leakoff stress, which is general saller. Fig. 2 shows the effects of changing the injector s choke. The curved full lines correspond to various choke settings, while the straight lines represent two different values of injectivity. If, for a fixed choke setting, the injectivity changes for soe reason, the response will stay on the fixed choke line. Thus, the path in the p-q plot is fully deterined by the choke setting, and in itself cannot say anything about the echanis leading to the change in injectivity.

2 2 SPE Analysis of injector data In this section we will show soe field exaples of injector response, focusing on effects of reservoir pressure build-up around the injection well and on fracture growth incidents. Reservoir Pressure Build-Up Effects Although a steady injection is aied for, an injector will in practice be shut in and reopened at irregular intervals during noral operation. It is generally attepted to close and reopen an injector in a controlled anner, with a constant choke closing/opening rate, but in certain situations a fast shut-in ay be necessary. Depending on the cause for the shut-in, the length of the shut-in interval ay vary fro a few hours or less up to several days. As a result, data fro the daily operation of an injector ay give inforation on local reservoir pressure build-up. The basics of the influence of reservoir pressure build-up around injectors were discussed in conjunction with Fig. 1. Fig. 3 shows a field exaple of pressure versus rate data for a period of about two weeks. Prior to the period, the injector was shut in for several days. This exaple deonstrates that the siple principles outlined above are relevant for field data: The 3 ain groupings of data (ephasized by the pairs of solid lines in the figure) result fro injection being shut-in for various periods of tie. The data indicated by the rightost solid lines (red data points) is for the start-up after several days of shut-in, while the leftost data is a controlled shutdown after soe days of injection at full rate. The iddle data are fro the start-up after a shorter shut-in period. Note how the intercept of the atrix and fracture lines occur at lower flow rate for the pressured-up cases, in accordance with Fig. 1. The vertical separation of the atrix injection lines is an indication of the change in near well pressure, while the vertical separation of the fracture lines is a response to the change in in situ stress seen by the fracture. Hence, plots like Fig. 3 ay be a quick ethod to deterine the reservoir stress path (Δσ h /Δp). However, uch caution is necessary, since teperature effects etc. ay strongly influence the situation. Also, the easured stress path is relevant for the situation around the injector, and not necessarily for the field itself. The data in Fig. 3 are particularly easy to interpret, since the typical tie for pressure build-up is long copared to the tie used for starting and stopping the injector. If the tie constants are ore siilar, the trends during start-up and shutdown will deviate fro straight lines. Fracture growth episodes As shown in Fig. 2 any pressure-rate change at constant choke appears as a line with negative slope in the pressure versus rate (p-q) plot. When reservoir pressure build-up around the injection well is significant, such negative slope changes will occur after any choke change. When the choke opening is increased, the initial response is to ove up-right along an injectivity line. Increased injection rate ay then locally increase reservoir pressure/stress, causing the negative slope, constant choke event (up-left). Siilarly, closing (reducing) the choke would first cause a reduced pressure/rate, a oveent down-left along the injectivity line. Reduced injection rate then results in a reduction in near wellbore reservoir pressure that ight then cause a negative p-q slope constant-choke event (down-right). Soeties, however, siilar behavior is observed even if the choke has been constant for a long tie. In such cases, a negative slope event is a signal of a change in injectivity not related to reservoir pressure build-up. Often, one will see that the increase in injectivity is only teporary, and in such cases the negative slope events stand out clearly fro the ain injector response. Fig. 4 shows an exaple with several events that can not be related to reservoir pressure build-up around the injection well. The plot quickly identifies soe events that ay be candidates for further investigation. Fig. 5 shows pressure and rate versus tie for one of the incidents in Fig. 4. The rate increases significantly over a few hours, while the injection pressure drops correspondingly. We ephasize that the choke was kept constant prior to, during and after the incident. Then, the situation is ore or less restored over a few hours. We interpret this as a fracture growth incident, which exposes fresh foration, possibly in a lower pressure regie. Then injectivity reduces as the faces of the new part of the fracture gradually plug, or reservoir pressure builds up around the recently exposed fracture. During the life of the injector, any such incidents occur, indicating episodic fracture growth. The size of the episodes ay be very significant, as deonstrated in Fig. 5, or uch less pronounced, as seen in Fig. 6. This response is an indication of repeated sall fracture growth incidents, resulting in a net increase in injectivity. A New Siulator Clearly, as seen in the injection/tie histories above, water injection is coplex. As opposed to siple hydraulic fracturing, changes in reservoir pressure/teperature have a strong ipact on fracturing and injectivity. Thus, the proble becoes highly coupled. Injection can alter the injection and the fracture geoetry, fluid loss fro the fracture, reservoir pressure/teperature/stress changes, etc. ust all be considered siultaneously. This coplex behavior also forces the use of Fully 3D, planar fracture geoetry siulations. Since the exact path of fracture growth cannot be predicted with any reasonable certainty (except aybe for very siple, single layer cases), sipler 2D / Pseudo 3D fracture growth odels are not applicable. The nuerical odel (using a cobination of finite eleent/finite difference techniques) eployed in the data analysis here iplicitly couples a planar, Fully 3-D, gridded fracture propagation odel to a 3-D single phase, ulti-coponent, variable teperature reservoir siulator. The coupled odel includes theral and pore pressure odification of stress, filter cake build-up and plugging on the fracture face inhibiting leakoff. The siulator was used to study the long ter injection (> 1 year) on fracture evolution and water placeent in the reservoir and to identify the iportance of the each of the phenoena of pereability contrasts (vertical and horizontal), stress contrasts, plugging, and injection rate. The details of the odel for fluid flow in the fracture and fracture propagation are presented in [2], and the details of the

3 SPE coupled fracture-reservoir odel are presented in [3]. An overview is included in Appendix A. In standard fracture odels leakoff is deterined analytically using the standard Carter leak-off coefficients. In the present odel fluid loss fro the fracture face is directly coputed fro flow into the reservoir. Finally, as discussed in ore detail below, a fluid filter cake effect was used to siulate the effects of water quality on fracture growth for injection above fracturing pressure. This C W, i.e., filter cake, effect was based on laboratory core data for a foration siilar in character to the zones studied here. Soe exaple results Discussions below present results deonstrating the role of therally induced waterflood fracturing in vertical sweep conforance of injection wells. In highly variable reservoir quality s, injection water tends to be injected into the best zones. This prootes cooling, and the resulting therally induced fracturing further enhances injection into these zones. This phenoenon has been thoroughly discussed previously [4,5], and typical field experience is early water breakthrough in the high pereability layers, leaving the other zones poorly swept with poor reserve recovery. While the exaple siulations below use data fro actual cases, the discussion is eant to be general. The reservoir sequence is shown in Fig. 7. Injection water has a downhole teperature of 25 C, and initial reservoir teperature is 80 C. The reservoir rock is quite soft, a Young s odulus of, 2 6 GPa (about psi). Since therally induced stress changes are related to the odulus (and the coefficient of theral expansion) Δσ E α T ΔT it ight be expected that cooling effects are not significant. However, for injection above fracturing pressure, the low odulus also leads to low net pressure (i.e., the injection pressure above fracture closure pressure), and thus, relatively sall stress changes ight be iportant. Only detailed, rigorous siulations can address such questions. The pre-injection in situ stresses are additional iportant data, and the stress profile in the figure is based on differential depletion easured prior to the start of injection. Initially, all s and shales in this reservoir have siilar horizontal stress. With depletion in the s, a stress contrast between /shale layers develops. Reservoir Goals For the exaple well in the figure, the injection goal is to achieve axiu injection into the zones fro Ideally, soe fracture growth upwards would provide injection and sweep into the zones fro 2450 to However, fracture growth into the high pereability zone with its base at 2445 ust be avoided. Effects of Injection Rate All siulations use a constant injection rate in each step. We first study the effect of rate, and want to find the axiu injection rate that can be injected into the s between Ideally we would like to see soe fracture growth to sweep the s above, but fracture growth into the extreely high pereability with base at 2445 ust be avoided. Table 1 shows the injection history for the well during the first 2 onths of injection. Fig. 8 shows the fracture geoetry after this injection. What is seen is that the well is fractured, but there is no need to extend the fracture ore than what is needed to bypass the plugged near wellbore area, i.e. there sees little risk of fracture growth out-of-zone fro this liited interval at this liited rate. The siulations assue very dirty water is injected. The C W of the odel represents the lab data shown in Fig. 9, where the sea water in this case had a particle (fines) content of That is, % by volue of the fluid was solid particles. Injection water saples fro the field have been taken in a few wells. They show a particle content typically uch less than 1/10 of the lab data. In actual fact, the lab tests do NOT show a physical filter cake, rather the apparent C W effect is caused by foration daage a short distance into the foration. Presuably this daage is related to the volue of particulates, just as a physical filter cake is related to the thickness of the filter cake (i.e., to the volue of fines). In that case, C W is related to the particle concentration kcake Δpcake CW 2 Cfines μfluid where C fines is the volue fraction of particles. Thus, if the actual particle concentration is 1/10 (375), then C W is increased by a factor of 10. When siulating the dirtier water, the need for bigger fractures is enhanced. The siulations should therefore represent a conservative view on the effect of fracture growth. Siulations with no particles in the water show no fracture is created. Naturally, there would be substantial benefit fro increased injection rate. Fig. 10 shows the results of an injection period of 200 days at /D. As seen, even this rate can be injected without undesired height growth. To deonstrate that any rate can be injected into this oderately pereable, a siulation with /D was run for an injection period of 200 days. Fig. 11 shows a fracture half-length of about 120, but alost no height growth outside the perforated interval. Thus, a different proble, we need to perforate the s higher up to achieve vertical sweep, but we still ust avoid injection into the extreely high pereability at the top. Siulations were then run to deterine if a fracture starting fro the next up ( ) would sustain injection without frac growth into the high pereability at the top. The width profile after 200 days at /D is shown in Fig. 12. The fracture has grown down into the lower, ore pereable, but still injects into newly perforated and the above. There is no risk of fracturing into the extreely pereable at the top. The figure also shows the leakoff contours, showing ost of the leakoff at the tip and doinated by the pereability. However, while the highest rates of injection are, of course, into the higher pereability zone, overall this injection scenario slightly favors the poorer quality rock as seen in Fig. 13. This appears to be a reasonable possible injection plan, and further investigation of higher rates would be required.

4 4 SPE Taking this one step further, i.e. perforating the next up and injecting at /D will result in a fracture growing into the top after 5 6 days. The width profile after 100 days of injection is shown in Fig. 14. Due to cooling effects, the fracture is igrating near totally into the overlying zone. Since fracture propagation is strongly affected by injection (increased reservoir pressure around the well and foration cooling) it should be possible to control fracture height growth. That is, cooling the foration by injecting at a low rate will reduce stress; rate can then be gradually increased. In this way one could force a fracture to be contained. Siulations were conducted to design such an injection schee for this exaple case. Assuing the sae perforation interval as the case above (where undesired, upward height growth occurred), injection start-up used a relatively low rate of /D for 50 days, /D for 50 days and finally /D. The evolution of the fracture is pictured in Fig. 15. In the first picture (after about 1 day), contours show the essentially instant response to injection pressure. Fracture closure pressure has increased by about 35 bar (at the wellbore) with no apparent cooling (stress reduction) effects yet appearing. Then after about 1 week (second picture), one sees a region of 0 stress change near the wellbore. The poro- and theral effects cancel. Finally, the third picture shows the stress change after about 50 days. This shows a stress reduction of about 15 bar in the injection zone. Note, however, that the stress reduction in the shale at 2454 is even greater ( 35 bar). Basically, the theral effects are slower/larger in the shale since the cooling is only by conduction (no convection fro fluid flow through the rock). However, there is NO poro-effect. Thus, the overall effect (for this case) is a greater stress reduction in the shale than in the. Thus, eventually fracture height growth ay occur. However, even though breakthrough ay occur, the large fracture area open in the deeper, lower pereability zones would continue to allow those zones to doinate injectivity long after breakthrough. For even better height confineent (for this case), a lower initial rate would be required in order to let the foration cooling ove out into the foration faster than the fracture length growth. This would then further reduce injection pressure, and totally prevent any fracture height growth into the shale. At that point, the shale cool down, stress reduction would depend solely on vertical heat conduction, further delaying shale stress reduction and subsequent height growth. The final picture shows the fluid loss (inflow into the foration) distribution at the end of 200 days. Fracture growth downward has contacted the lower, and upward height growth is nearing the overlying, high pereability zone. The ajor difference between upward/downward growth is that the upper shale is slightly thicker, thus cooling by conduction takes additional tie. While not plotted here, eventually after a year, the fracture did penetrate the high pereability zone. However, even for onths after breakthrough, the deeper, lower pereability zones still doinated injectivity. Conclusions As expected, and discussed any ties in the literature, reservoir cooling has a strong effect on fracturing. Even for this low odulus foration, there is a strong tendency to keep fractures well confined. However, even where shale barriers exist, eventually cooling via conduction ay reduce the stress in the shale and allow vertical fracture igration. Start-up procedures can be used to reduce or delay unwanted height growth. However, the exact procedure or injection pattern will depend on the specific conditions of pereability, fluid/foration teperatures, etc. In general, however, cooling of shale layers via conduction will eventually cause stress reduction and fracture height growth ay resue. Quite dirty water can be injected as long as fractures are allowed to grow with no danger of fracturing into forbidden zones. The cobination of detailed injection data, a siple p-q plot, and rigorous coupled odel (siultaneously considering injection, fracture growth, teperature, pore pressure, etc.) can provide a powerful engineering tool for anageent of water injectors. Noenclature A = Area A p = Poroelastic constant A T = Theroelastic constant B = Biot coefficient C = Concentration C t = Copressibility E = Young s odulus K = Stiffness atrix T = Teperature V = Volue k = pereability p = Pressure q = Flow rate w = width α T = Coefficient of theral expansion φ = Displaceent potential σ = stress μ = Viscosity ν = Poisson's nuber References 1. Perkins, T.K. and Gonzalez, J.A., The effect of theroelastic stresses on injection well fracturing. Soc. Petr. Eng. J., 25, 78 88, M. B. Sith, A. B. Bale, L. K. Britt, H. H. Klein, E. Siebrits, and X. Dang, Layered Modulus Effects on Fracture Propagation, Proppant Placeent, and Fracture Modeling,. SPE 71654, presented at the 2001 SPE Annual Technical Conference and Exhibition. New Orleans, Louisiana, 30 Septeber 3 October Michael B. Sith, Michael Bose, Henry H. Klein, Brent R. Ozenne, Ron S. Vandersypen, High-Pereability Fracturing: "Carter" Fluid Loss or Not, SPE presented at the SPE International Syposiu and Exhibition on Foration Daage Control held in Lafayette, Louisiana, February 2004.

5 SPE Clifford, P.J., Siulation of Waterflood Fracture Growth with Coupled Fluid Flow, Teperature and Rock Elasticity, presented at the 2 nd joint IMA/SPE European Conference on the Matheatics of Oil Recovery, Cabridge, July Clifford, P.J., Berry, P.J., Hongren, G., Modeling the Vertical Confineent of Injection-Well Theral Fractures, SPEPE, 6(6), , E. J. L. Konig, Fractured Water Injection Wells Analytic Modelling of Fracture Propagation, SPE (Unsolicited), Appendix A The fracture evolution is deterined by volue conservation of the fluid, V +Δ ( qx + qz) = qp + ql (A-1) t where V is the local fracture volue = way, w is the fracture width, Ay is the area of the fracture face, qx and qz are the voluetric flow rates along the length and height of the fracture respectively. These flow rates are functions of the pressure gradient, the (non-newtonian) viscosity, and the width. qp is the pup rate and q l is the leakoff rate at the fracture face p. The fracture width is related to the pressure through the fracture stiffness, [ K][ w] = [ p σ ] (A-2) K is the stiffness atrix, pre-calculated using the finite eleent ethod for varying layer oduli or analytically for unifor odulus using a boundary integral approach. p is the pressure and σ is the stress. In the standard fracture odels the leakoff is deterined using the standard Carter leak-off coefficients. In the present odel the fluid loss fro the fracture face is directly fro flow into the reservoir. The leak-off rate is Ak y filtrate( preservoir pfracture) ql = (A-3) μ filtratell where k filtrate is the pereability inside the fracture-reservoir face, and can include relative pereability effects;. μ filtrate is the viscosity of the fluid inside the fracture-reservoir face, and it can include non-newtonian and teperature effects. p reservoir is the pressure at the reservoir face, and p fracture is the pressure at the fracture face. L l is a length that includes gel and solids filtercake buildup on the fracture face, the distance of the invaded zone of the leak-off fluid, and the copressibility of the reservoir fluid.. The volue conservation in the reservoir is given by p k k x p y p kz p Ct = 0 (A-4) t x μ x y μ y z μ z C is the copressibility of the reservoir fluid; t k x, k y, kz are the pereabilities in the three space dientions; μ is the fluid viscosity. Equations (A-1) (A-4) are solved siultaneously for the fracture width and the pressure in the fracture and reservoir. Equations for the conservation of energy are solved to provide the teperature in the fracture and reservoir. As the injected fluid leaks off fro the fracture the reservoir pore pressure increases and the teperature increases or decreases depending on the relative injected and reservoir teperatures. The pressure and teperature changes have a direct effect on the stresses confining the fracture. Following Konig [6] the poro-thero stress change is E Δ σ ij = ϕ+ ApΔ pδij + AT ΔTδij (A-5) 1+ v xi xj φ is the displaceent potential which is a solution to the Poisson Equation 2 1+ ν 1+ ν φ = ApΔp ATΔT (A-6) E E Δp is the pressure change fro the initial reservoir pressure, and ΔT is the teperature change fro the original reservoir teperature. Ap is the poro-elastic constant defined as 1 2ν Ap = B (A-7) 1 ν where B is Biot s constant. AT is the thero-elastic constant defined as EαT AT = (A-8) 1 ν where α T is the theral expansion coefficient. Equations (A-5) and (A-6) are solved to give the change in local fracture confining stress. The updated stresses are used in Equation (A-2) to give the fracture response to the stress changes.

6 6 SPE Figure 1 Basic injector response. The full (black) line shows the transition fro atrix to fracture injection at the level indicated by the dotted gray line. The dashed (blue) line shows the effect of cooling. Siilarly, the dash-dot line (red) shows how reservoir pressure increases around the injector changes both atrix and fracture injectivity. Note how the crossing oves towards lower rate, as discussed in the text. Figure 3 Field exaple of reservoir pressure build-up around an injector. The data points are colour coded with rainbow colors, with early data being red and late date being blue. The solid black lines indicate the atrix and fracture injection regies for three different levels of pressure build-up around the injector, as dicussed in the text. Figure 2 Basic injector response. The dashed (blue) lines correspond to two different injectivities, while the solid (black) lines apply for different choke settings. If injectivity changes with constant choke, the response will ove along the choke curves, as illustrated by the thick (red) line segents. Figure 4 Field exaple of fracture growth incidents. Most of the data points gather around the fracture injection line, but there are several negative slope events corresponding to teporary increase in injectivity. One of the events is shown in ore detail in Fig. 5.

7 SPE Figure 5 Flow rate (upper) and pressure (lower) versus tie for one of the fracture growth incidents in Fig. 4. Figure 6 Field exaple of a series of saller fracture growth incidents, leading to a net increase in injectivity. Note, however, how the injectivity decreases following each event Heidrun A49 Lower Tilje Injection_LastSP 2500 Silt () Drag logs onto graphs as desired GR API RHOB g/c3 Pcl (Bar) E (MMpsi) K Ic Si l L Figure 7 Geologic layering for exaple siulations

8 8 SPE Table 1 Actual Startup Injection Rate History Injection - ( 3 /D) Tie - (Days) in Width - Total in Figure /D in Fracture Penetration () Width - Total in Fracture Penetration () Figure 8 Fracture Geoetry After Startup Injection Constant Flowrate Variable Δp Figure /D Start Dirty Water 5 icron particles Solids Fraction Pore Volues Injected Loss Volue (cc/c ) C W= X Slope = ft/ in Tie (in) Figure 9 C W for Dirty Injection Water

9 SPE in Fracture Penetration () Width - Total in Figure 14 Injection into Top Zone at /D. The fracture penetrates into the overlying, forbidden high pereability zone in < 1 week. Fracture Geoetry after 200 Days in Fracture Penetration () Injection Distribution after 200 Days Figure 12 Injection of /D into iddle zone ( ) Leakoff M3/Day Fraction "kh" Fraction Injection Figure 13 Cuulative Injection Distribution ( /D for 200 Days)

10 10 SPE in (5) (4) (3) (2) (1) Stress Change Bar Fracture Penetration () in (5) (4) (3) (2) (1) Stress Change Bar Fracture Penetration () in (5) (4) (3) (2) (1) Stress Change Bar Fracture Penetration () in Leakoff M3/Day Fracture Penetration () Figure 15 Effect of Injection Start-Up on Fracturing