**6. Conclusions**

root-time plot for *t* >0.15*Tm* . If we could detect the time at which this departure occurs then, we have some information with which to estimate the productive fracture spacing. Even if the entire production history to date is in the linear flow regime, we can at least make an estimate

in the linear flow regime, we can at least make an estimate of a lower bound on the fracture spacing.

independent of the fracture spacing. According to the analysis presented earlier we should expect the cumulative production data to deviate from a straight-line in the root-time plot for *Tm <sup>t</sup>* 0.15 .If we could detect the time at which this departure occurs then, we have some information with which to estimate the productive fracture spacing. Even if the entire production history to date is

A common view of production mechanisms in shales is "because the formations are so tight gas can be produced only when

permeability=10nd permeability=100nd permeability=200nd

permeability and porosity) and what we may term our (engineering) attempts at nurture (including completion and stimulation parameters). Of key importance is the productive fracture surface, which unfortunately is difficult to estimate a priori. However,

Typically, there is no indication of fracture interference during production even after several years, which suggests that

It is instructive to estimate the matrix diffusion time for typical values of the fracture spacing and matrix permeability. The results are shown in Figure 13. The diffusion time increases quadratically with the fracture spacing and inversely with the matrix permeability. Typical values for the diffusion time are quite low. For example, if, as we expect, linear flow continues for at least 3 years, then we should expect to see a diffusion time of the order of 20 years. Figure 13 suggests that the productive fracture spacing is likely to be of the order

3000 ft lateral would be of the order of 150 Msq ft, which again is unreasonably large.

**Matrix drainage time**

Figure 13.The impact of fracture spacing on the time to produce 90% of the gas in place.

**Figure 13.** The impact of fracture spacing on the time to produce 90% of the gas in place.

0 50 100 150 200 250 300

fracture spacing (ft**)**

In figure 13 we have identified the diffusive time scale with the matrix drainage time. As we showed above, 90% of the total gas in the pore space between the fractures has been drained by this time. A time scale of about 20 years is at least consistent with the indus‐ try estimates of the effective production lifetime of these wells. It is worth noting here the consequences of much smaller fracture spacing. For a fracture spacing of only 10 ft, we estimate that 90% of the total gas production will have occurred within the first few months of production, which is quite unrealistic. Note also that the surface area of planar frac‐ tures only 10 ft apart in a 3000 ft lateral would be of the order of 150 Msq ft, which again

our interpretation of the production data suggest the following

the productive fracture spacing is at least 100 ft.

Productive fracture surface area ~1-6 Msqft and probably within 2-4 Msq ft.

Time to drain 90% of the fractured region or matrix blocks: ~10-20 years

The volume of these productive fractures is very much less than the volume of water pumped, but

Productive fracture volume scales approximately with the volume of proppant placed.

of a lower bound on the fracture spacing.

352 Effective and Sustainable Hydraulic Fracturing

is likely to be of the order of 100 ft or more.

of 100 ft or more.

**6. Conclusions** 

**matrix**

**drainage time**

**(years)**

respect.

is unreasonably large.

It is instructive to estimate the matrix diffusion time for typical values of the fracture spacing and matrix permeability. The results are shown in Figure 13. The diffusion time increases quadratically with the fracture spacing and inversely with the matrix permeability. Typical values for the diffusion time are quite low. For example, if, as we expect, linear flow continues for at least 3 years, then we should expect to see a diffusion time of the order of 20 years. Figure 13 suggests that the productive fracture spacing A common view of production mechanisms in shales is "because the formations are so tight gas can be produced only when extensive networks of natural fractures exist" [6]. To this extent gas production from some of the shallower (Devonian) shales is similar to gas production from coal. As we have discussed earlier in this paper, we expect that the deeper gas shales differ in this respect.

In figure 13 we have identified the diffusive time scale with the matrix drainage time. As we showed above, 90% of the total gas in the pore space between the fractures has been drained by this time. A time scale of about 20 years is at least consistent with the industry estimates of the effective production lifetime of these wells. It is worth noting here the consequences of much smaller fracture spacing. For a fracture spacing of only 10 ft, we estimate that 90% of the total gas production will have occurred within the first few months of production, which is quite unrealistic. Note also that the surface area of planar fractures only 10 ft apart in a Using a new semi-analytic production model, we have analyzed production data from a number of shale gas wells in several different North American shale gas plays. Interpretation of the results suggest that productivity is largely determined by a small group of parameters that may be decomposed into two sub-groups representing the nature of the reservoir (such as matrix permeability and porosity) and what we may term our (engineering) attempts at nurture (including completion and stimulation parameters). Of key importance is the produc‐ tive fracture surface, which unfortunately is difficult to estimate a priori. However, our interpretation of the production data suggest the following


We are led to the conclusion that almost all the fracturing fluid pumped during a multi-stage horizontal well fracturing operation in the shales serves to open a vast, and possibly complex, network of natural fractures and that these fractures do not make a significant contribution to the well's productivity. We are led inevitably to questions concerning the conductivity of these, largely unpropped, fractures and to investigate the rock and fluid mechanisms that seemingly prevent them from being productive. The role of the fracturing fluid (usually slickwater) in this process should now be investigated from this new perspectivel

### **Nomenclature**

extensive networks of natural fractures exist" [6]. To this extent gas production from some of the shallower (Devonian) shales is k – permeability

similar to gas production from coal. As we have discussed earlier in this paper, we expect that the deeper gas shales differ in this *φ* – porosity *μ* – gas viscosity *λ* – dual porosity transmissivity factor (defined in equation (17))

Using a new semi-analytic production model, we have analyzed production data from a number of shale gas wells in several *c* – gas compressibility

different North American shale gas plays. Interpretation of the results suggest that productivity is largely determined by a small group of parameters that may be decomposed into two sub-groups representing the nature of the reservoir (such as matrix *cf* – fracture conductivity


[2] Warren, J.E. and Root, P.J.: "The Behavior of Naturally Fractured reservoirs," SPEJ,

The Role of Natural Fractures in Shale Gas Production

http://dx.doi.org/10.5772/56404

355

[3] King, G.R, Ertekin, T, and Schwerer, F.C., "Numerical simulation of the Transient Be‐ havior of Coal- Seam Degasification Wells," SPE Formation Evaluation, April, 1986.

[4] Schettler, P.D., Parmely, C.R. and Lee, W.J., "Gas Storage and Transport in Devonian

[5] Luffel, D.L., Hopkins, C.W. and Schettler, P.D., "Matrix Permeability Measurement

[6] Carlson, E.S. and Mercer, J.C., "Devonian Shale Gas production: mechanisms and

[7] Gatens, J.M., Lee, W.J., and Rahim, Z.: "Application of an Analytic Model to History Match Devonian Shales Production Data," Paper SPE 14509 presented at the 1985

[8] Kuuskraa, V.A., Wicks, D.E. and Thurber, J.L.: "Geologic and Reservoir Mechanisms Controlling Gas Recovery from the Antrim Shale," Paper SPE 24883 presented at the 67th Annual SPE Technical Conference and Exhibition, Washington, D.C., October

[10] Luo, S., Neal, L., Arulampalam, P. and Ciosek, J.M.: "Flow Regime Analysis of Multistage Hydraulically-fractured Horizontal Wells with Reciprocal Rate Derivative Function: Bakken case Study," Paper CSUG/SPE 137514 presented at the Canadian Unconventional Resources and International Petroleum Conference, Calgary, Alber‐

[11] Van Golf-Racht, T.D.: "Fundamentals of Fractured Reservoir Engineering," Develop‐ ments in Petroleum Science, vol 10, Elsevier Scientific Publishing Company, 1982. [12] Kazemi, H.: "Pressure Transient Analysis of naturally Fractured Reservoirs with Uni‐

[13] Kucuk, F. and Sawyer, W.K.: "Transient Flow in Naturally Fractured Reservoirs and Its Application to Devonian Gas Shales," Paper SPE 9397 presented at the 55th Annu‐

[14] Walton, I.C.: "Shale Gas Production Analysis, Phase I Final Report," EGI internal re‐

[15] Bello, R.O. and Wattenbarger, R.A.: "Rate Transient Analysis in Naturally Fractured Shale gas Reservoirs," Paper SPE 114591 presented at the CIPC/SPE Gas Technology

al Technical Conference and Exhibition, Dallas, Texas, September 21-24 1980.

form Fracture Distribution," SPEJ (Dec 1969), 451-61; Trans AIME, 246

Eastern Regional meeting, Morgantown, W Virginia, November 6-8, 1985.

September 1963. (Originally published as SPE 00426, 1962).

Shales." SPEFE, September 1989.

4-7, 1992.

of Gas Productive Systems,", SPE 26633 (1993).

[9] Kent Bowker, HAPL Technical Workshop, 2008)

Symposium, Calgary, Alberta, June 16-19, 2008.

ta, Canada, 19-21 October, 2010.

port 100983, 2012.

Simple Models," SPE 19311, 1989 (also JPT April 1991).


#### **Subscripts**


### **Author details**

Ian Walton and John McLennan

Energy and Geoscience Institute, University of Utah, USA

#### **References**

[1] A Guide to Coalbed Methane Reservoir Engineering, Saulsberry, J.L., Schafer, P.S., and Schraufnagel, R.A. (Editors), Gas Research Institute Report GRI-94/0397, Chica‐ go, Illinois (March 1996).


*p* – pressure

*m* – gas pseudo-pressure

354 Effective and Sustainable Hydraulic Fracturing

*q* – production or flow rate *Q* – cumulative production

*T* – reservoir temperature

*A* – productive fracture surface area

*Z* – real gas compressibility factor

*z* – co-ordinate normal to fracture surface

*r* – radius (wellbore)

*L* – fracture spacing

**Subscripts**

*m* – matrix

i – initial

s – surface

w – wellbore

**Author details**

**References**

Ian Walton and John McLennan

go, Illinois (March 1996).

Energy and Geoscience Institute, University of Utah, USA

[1] A Guide to Coalbed Methane Reservoir Engineering, Saulsberry, J.L., Schafer, P.S., and Schraufnagel, R.A. (Editors), Gas Research Institute Report GRI-94/0397, Chica‐

*ch* – characteristic *D* – dimensionless

*t* – time

*CP* – production coefficient (defined in equation (16))


[16] Economides, M.J. and Nolte, K.G:"Reservoir Stimulation," Prentice Hall, Third Edi‐ tion, 2000.

**Section 5**

**Well Completions and Fracture Initiation 1**

**Well Completions and Fracture Initiation 1**

[16] Economides, M.J. and Nolte, K.G:"Reservoir Stimulation," Prentice Hall, Third Edi‐

tion, 2000.

356 Effective and Sustainable Hydraulic Fracturing

**Chapter 17**

**Do Perforated Completions Have Value for Engineered**

Engineered or enhanced geothermal systems (EGS) differ from conventional hydrother‐ mal reservoirs in that supplementary hydraulic stimulation is required to create surface area needed for heat exchange, and to allow adequate fluid production. Historically, geo‐ thermal wells have been straight hole or inclined and usually employ barefoot comple‐ tions. If horizontal drilling and hydraulic fracturing experience, refined to some extent with recent shale gas and shale oil stimulation campaigns, can be adapted for geothermal applications, it may be possible to improve the chances for successful EGS. One central issue for vertical, inclined, extended reach or horizontally drilled wells is whether there is merit in landing and cementing casing. This would allow discrete zones to be frac‐ tured, isolate thief zones or low temperature zones, allow future remediation and facili‐

Most experienced geothermal operators balk at perforated and cemented completions. The arguments can be legitimate. There are supplementary costs associated with this completion, and the temperatures can make cementing and perforating challenging. Plugging of existing fracture systems from casing and cement is also proposed as a problem – which is easily overcome by the supplementary stimulation required. On the other hand, simple calculations suggest that proximal and interconnected fracture systems, natural or otherwise, are required for economic viability in all but the hottest scenarios. To effectively develop multiple fracture systems, wellbore isolation seems to be a natural requirement. One legitimate method to accomplish this is diversion, but the question remains as to how many intersected fractures can be stimulated. Another option is cementing and perforating. A comparative and realistic analysis is done to assess the impact of perforation skin, tortuosity associated with shear

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© 2013 Glauser et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

© 2013 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution,

**Geothermal Systems**

http://dx.doi.org/10.5772/56211

**Abstract**

Walter Glauser, John McLennan and Ian Walton

Additional information is available at the end of the chapter

tate generation of multiple fracture systems.
