**Abstract**

It is common to envision and design hydraulic fractures as if they were simple, planar fea‐ tures that are relatively consistent in width and durable in their flow capacity. Production forecasting is frequently based on a simplified description of the reservoir as a homogene‐ ous single productive layer. In rare instances the pay intervals may be simulated with as many as a dozen layered strata, but even the most meticulous reservoir engineer may mis‐ takenly assign each layer a highly conductive, durable connection with the wellbore. When analyzing the resulting production data, similar assumptions are made, which can errone‐ ously reinforce these misconceptions.

Although our industry has been confronted with photographic evidence from minebacks and core-throughs of actual fractures, we have typically failed to incorporate those complex‐ ities and challenges into our design, interpretation, and optimization processes. Similarly, we frequently fail to recognize the challenges of highly laminated and highly compartmen‐ talized reservoirs. In many resource plays, hydraulically stimulated horizontal wells appear to be the only completion technique that can achieve economic production rates from these low permeability reservoirs. However the productivity and ultimate recovery from these horizontal wells will be increasingly reliant on durable hydraulic fractures to contact and drain the hydrocarbons through highly laminated formations for the decades necessary to deplete low permeability reservoirs. Oversimplified models typically result in poorly de‐ signed completions and missed opportunities. Frequently, the underperformance of a well will be blamed on "poor reservoir quality" instead of correctly recognizing the inadequacy of our created fractures.

© 2013 M. C.; 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, and reproduction in any medium, provided the original work is properly cited.

This paper will examine five limitations of hydraulic fractures and interpretation techni‐ ques, and describe the increases in well productivity that can be achieved when efforts are made to address and compensate for these deficiencies.

Although chemical engineers clearly recognized that Darcy's flow would not describe pressure losses in porous media, early frac engineers disregarded non-Darcy and multiphase flow effects, and further assumed a single homogeneous reservoir layer was contacted by a highly conductive fracture that permanently connected the wellbore to the hydrocarbons. These assumptions allowed the "optimization" of frac treatments to become a mathematically simple routine. Two subsequent generations of petroleum engineers have filled our literature and conventional wisdom with simulations and "rules of thumb" that would allow us to optimize these mythical ideal fractures. Unfortunately, many of the assumptions are wrong, and our

Even if fractures were simple, wide features, with perfectly uniform proppant arrangements throughout the entirety of the fracture length and height, our industry would still overestimate the flow capacity of fractures by several orders of magnitude. Figure 2 shows the apparent

*Realistic Conductivity Reductions*

flow capacity of proppant packs, measured in the laboratory.

**7000**

**5715**

**500 1500**

quently 50 to 1000 times lower than published values [1]

**0**

**1000 2000**

31

**3000 4000 5000**

**Effective Conductivity (md-ft)** 

**6000 7000**

> **182 1137**

**API Test Modified 50-Hour Test**

**72 672**

**"Inertial Flow" with Non-Darcy Effects**

**3481**

**24 225**

**Lower Achieved Width (1 lb/sq ft)**

**Figure 2.** Even in simple, planar proppant packs with uniform proppant distribution, the effective conductivity is fre‐

Conductivity data provided by most proppant vendors, and utilized in most production simulators are collected with test procedures similar to the left two categories of bar columns in Figure 2. When testing is more sophisticated, with realistic velocities of multiphase fluids through proppant packs subjected to gel damage and cyclic stress oscillations, the pres‐

**1243**

**<sup>5</sup> <sup>49</sup> 479 1.4 <sup>14</sup> <sup>144</sup>**

**Low Quality Sand Best Quality Ottawa Sand Premium Light Weight Ceramic**

**Multiphase Flow**

**50% Gel Damage**

**Effective conductivities can be less than 1% of API test values**

**0.6 <sup>7</sup> <sup>130</sup>**

0.0001 D-m

Five Things You Didn't Want to Know about Hydraulic Fractures

http://dx.doi.org/10.5772/56066

83

99.9% reduction

0.001 D-m

99.7% reduction

0.029 D-m

98.6% reduction

**Fines Migration / Plugging**

**0.3 <sup>4</sup> <sup>96</sup>**

**Cyclic Stress**

fracs are not optimized.

**2. Complex flow regimes**

**Keywords** Frac optimization, resolving non-unique solutions, proppant degradation, realistic conductivity, laminated reservoirs, complexity, restimulation
