*Realistic Conductivity Reductions*

**Figure 2.** Even in simple, planar proppant packs with uniform proppant distribution, the effective conductivity is fre‐ quently 50 to 1000 times lower than published values [1]

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‐ sure losses are often found to be orders of magnitude higher than indicated by reference data [1,2,3].

**4. Heterogeneous reservoirs**

Production forecasting is greatly simplified if the reservoir can be described as a uniform layer with predictable, consistent permeability in the vertical and horizontal directions. However, sedimentary rocks were formed from hundreds or thousands of sequential layers of sediment

**Figure 4.** On every scale, formations may have laminations that hinder vertical permeability and fracture penetration. Shown are thin laminations in the Middle Bakken [11], layering in the Woodford [outcrop photo courtesy of Hallibur‐

**1.** Vertical perm is terrible. Often the vertical perm is only a tiny fraction of the horizontal perm; kv/kh <0.001. Oil and gas do not move easily in the vertical direction through rock. If you want to drain it, you have to frac it. Especially with horizontal wells drilled into a single layer, the frac engineer must create a durable, conductive pathway breaching the laminations within the hydrocarbon-bearing intervals if we have a prayer of draining the reserves from these tight, laminated resource plays, unless pre-existing natural fractures

**2.** Laminations hinder frac penetration [13]. Fracs don't like to grow through a series of

Figure 5 depicts conceptualized fracture branching as it grows through a laminated formation. Figure 6 shows minebacks of actual fracturing treatments performed at the Nevada test site and Figure 7 shows a core-through of a treatment in the Piceance Basin of western Colorado.

Niobrara A Chalk Niobrara A Marl

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as shown in Figure 4. Productive lenses can have varying lateral extent.

ton], and large scale laminations in the Niobrara [adapted from 12] [13]

The consequences of these laminations are two-fold:

provide a vertical flow path.

**5. Complex frac geometry**

bonded and unbonded layers (Fig 5).

## **3. Conductivity degrades**

Even the meager amount of effective conductivity shown in Figure 2 appears to be unsustain‐ able. Five different researchers have published the performance of proppants when tested in the laboratory for weeks instead of hours Montgomery [4], McDaniel [5], Cobb [6], Hahn [7], Handren [8]. All five have shown that proppants lose conductivity over time, with one representative test shown in Figure 3. Some proppants are more durable than others, and some laboratory conditions will more rapidly degrade proppant, but not a single proppant pack in the lab has sustained flow capacity without continued particle breakage and compaction during extended testing. The degradation mechanism in these tests has nothing to do with chemical damage, scale deposition, or diagenesis – these conductivity losses are related to the strength of the particles, and show similar trends when tested in dry nitrogen gas, in oil, or in brine, when confined between sandstone, stainless steel, or Teflon. [5, 9, 10]. It is surprising that none of our models incorporate frac degradation over time, despite unanimous evidence that conductivity declines.

**Figure 3.** Extended duration tests routinely show continued mechanical crush and loss of flow capacity of proppant packs [5]

### **4. Heterogeneous reservoirs**

sure losses are often found to be orders of magnitude higher than indicated by reference

Even the meager amount of effective conductivity shown in Figure 2 appears to be unsustain‐ able. Five different researchers have published the performance of proppants when tested in the laboratory for weeks instead of hours Montgomery [4], McDaniel [5], Cobb [6], Hahn [7], Handren [8]. All five have shown that proppants lose conductivity over time, with one representative test shown in Figure 3. Some proppants are more durable than others, and some laboratory conditions will more rapidly degrade proppant, but not a single proppant pack in the lab has sustained flow capacity without continued particle breakage and compaction during extended testing. The degradation mechanism in these tests has nothing to do with chemical damage, scale deposition, or diagenesis – these conductivity losses are related to the strength of the particles, and show similar trends when tested in dry nitrogen gas, in oil, or in brine, when confined between sandstone, stainless steel, or Teflon. [5, 9, 10]. It is surprising that none of our models incorporate frac degradation over time, despite unanimous evidence

**Figure 3.** Extended duration tests routinely show continued mechanical crush and loss of flow capacity of proppant

All published lab data show proppants continue to crush, compact, rearrange over time and lose conductivity. SPE 12616, 14133, 15067, 110451,128612, 134330, 136757, Hahn, *Drilling* Vol 47, No 6, April 1986

This degradation has nothing to do with "diagenesis". Occurs dry, wet, mineral oil, N2 gas, between Teflon, steel, sandstone or shale

> Some proppants are more durable than others. But none are "constant" Why don't engineers recognize this?

data [1,2,3].

**3. Conductivity degrades**

84 Effective and Sustainable Hydraulic Fracturing

that conductivity declines.

packs [5]

**McDaniel , SPE 15067** 

Production forecasting is greatly simplified if the reservoir can be described as a uniform layer with predictable, consistent permeability in the vertical and horizontal directions. However, sedimentary rocks were formed from hundreds or thousands of sequential layers of sediment as shown in Figure 4. Productive lenses can have varying lateral extent.

**Figure 4.** On every scale, formations may have laminations that hinder vertical permeability and fracture penetration. Shown are thin laminations in the Middle Bakken [11], layering in the Woodford [outcrop photo courtesy of Hallibur‐ ton], and large scale laminations in the Niobrara [adapted from 12] [13]

The consequences of these laminations are two-fold:


#### **5. Complex frac geometry**

Figure 5 depicts conceptualized fracture branching as it grows through a laminated formation. Figure 6 shows minebacks of actual fracturing treatments performed at the Nevada test site and Figure 7 shows a core-through of a treatment in the Piceance Basin of western Colorado.

**Figure 5.** Instead of perfectly vertical fractures (left) it may be appropriate to anticipate difficulty creating and sustain‐ ing a conductive fracture throughout the entire pay interval [outcrop photo courtesy of Halliburton [13].

**Mesaverde MWX test, SPE 22876**

**Pro:** Complex fracs increase the reservoir contact (beneficial in nano-Darcy shales?)

with sufficient hydraulic continuity [adapted from 17]

resin coated sand recovered [1, 16]

*Physical evidence of fractures nearly always complex*

> **Con:** Complex fracs complicate the flow path, and provide less cumulative conductivity than simple, wider

 32 Fracture Strands Over 4 Ft Interval HPG gel residue on all surfaces Gel glued some core together (>6

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yrs elapsed post-frac!) All observed frac sand (20/40 RCS) pulverized <200 mesh A second fractured zone with 8 vertical fractures in 3 ft interval

7100 ft TVD [2160m]

observed 60 feet away (horizontally) <sup>28</sup>

**Figure 7.** In the Piceance Basin, cores through a created fracture document 40 fracture strands, with only pulverized

Clearly, there is evidence that fractures can grow in much more complicated manners compared to the simple, planar features that are typically presumed in our designs and

*Is Fracture Complexity Good or Bad?*

Very Complex Fracture Network

**Figure 8.** Fracture complexity increases reservoir contact, but challenges our ability to create a durable proppant pack

fractures [SPE 115769] Adapted from SPE 77441

Simple Fracture Complex Fracture

"optimization" attempts. What are the implications of complexity shown in Figure 8?

**Figure 6.** Photographs of mine backs at the Nevada test site demonstrate complexity [1, 14,15]

**Figure 7.** In the Piceance Basin, cores through a created fracture document 40 fracture strands, with only pulverized resin coated sand recovered [1, 16]

*Woodford Shale Outcrop*

ing a conductive fracture throughout the entire pay interval [outcrop photo courtesy of Halliburton [13].

**Figure 6.** Photographs of mine backs at the Nevada test site demonstrate complexity [1, 14,15]

**Figure 5.** Instead of perfectly vertical fractures (left) it may be appropriate to anticipate difficulty creating and sustain‐

**NEVADA TEST SITE HYDRAULIC FRACTURE MINEBACK**

Narrower aperture plus greater stress in horizontal steps?

Failure to breach all laminae?

86 Effective and Sustainable Hydraulic Fracturing

Some reservoirs pose challenges to effectively breach and prop through all laminations

Our understanding of frac barriers and kv should influence everything from lateral depth to frac fluid type, to implementation

> Clearly, there is evidence that fractures can grow in much more complicated manners compared to the simple, planar features that are typically presumed in our designs and "optimization" attempts. What are the implications of complexity shown in Figure 8?

**Figure 8.** Fracture complexity increases reservoir contact, but challenges our ability to create a durable proppant pack with sufficient hydraulic continuity [adapted from 17]

Hydraulic fractures must achieve two primary objectives. They must: Figure 8. Fracture complexity increases reservoir contact, but challenges our ability to create a durable proppant pack with sufficient hydraulic

fractured interval, along with three plausible production matches.


Complex, branching fractures do an excellent job of touching rock. However, they challenge our ability to place a commensurate degree of conductivity. Branching, complex features are often ineffectively propped, with risk of insufficient conductivity and continuity. 1. Touch rock (contact hydrocarbons) 2. Provide a durable conduit for hydrocarbons to flow to the well with acceptable pressure losses (sufficient conductivity)

Complex, branching fractures do an excellent job of touching rock. However, they challenge our ability to place a commensurate

pointing well productivity can always be blamed on the geology – with no irrefutable proof

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There are certainly more than five deficiencies in our stimulation designs and our techniques

**1.** Hydrocarbons move in a complex manner within propped fractures, increasing the pressure losses by 50 to 1000-fold over common expectations, even if the fractures are

**2.** Fracture conductivity is not constant. Lab data suggest that all conventional proppant

**3.** Reservoirs are laminated and compartmentalized. Especially with horizontal drilling, ultimate recovery is far more dependent on fracture continuity through laminations than in vertical wells in which each prospective layer can be perforated and individually stimulated. With low perm reservoirs, significantly longer well life (and proppant

**4.** Fractures develop varying degrees of complexity. This is both good and bad. Reservoir contact is increased as fractures branch, twist, and energize pre-existing planes of weakness. However, this complexity challenges our ability to place a durable, hydrauli‐ cally continuous proppant pack with conductivity commensurate to carry hydrocarbons

**5.** History-matching of production data is surprisingly non-unique. An engineer can reinforce misconceptions throughout an entire career without encountering any results that cannot be matched with a simple, planar frac of durable, high conductivity in a homogenous reservoir. Underperformance can always be attributed to other factors. While this is a fairly depressing view of the problem, there are techniques to remove some of the uncertainty and ambiguity allowing significant improvement in the performance of

Several datasets and techniques can be used to more uniquely describe the performance of

**•** Wells that are restimulated. When we refrac a well, we have an opportunity to history-match the production from the initial and subsequent stimulation treatments using only a single reservoir description. Difference in well production must be uniquely attributed to the frac

to analyze well production. However, the five issues described in this paper include:

types suffer continued crush and compaction over time.

durability) will be required to drain the available reserves.

with an acceptably small pressure loss.

stimulation treatments.

propped fractures [19]:

**8. Removing the uncertainty**

that the fracture was insufficient.

**7. Discussion of five deficiencies**

planar and fully propped.

production data from a single well. Figure 9 shows the production history (decline curve and cumulative production) from a single

There are certainly more than five deficiencies in our stimulation designs and our techniques to analyze well production. However,

1. Hydrocarbons move in a complex manner within propped fractures, increasing the pressure losses by 50 to 1000-fold over

2. Fracture conductivity is not constant. Lab data suggest that all conventional proppant types suffer continued crush and

3. Reservoirs are laminated and compartmentalized. Especially with horizontal drilling, ultimate recovery is far more dependent on fracture continuity through laminations than in vertical wells in which each prospective layer can be perforated and individually stimulated. With low perm reservoirs, significantly longer well life (and proppant durability)

4. Fractures develop varying degrees of complexity. This is both good and bad. Reservoir contact is increased as fractures branch, twist, and energize pre-existing planes of weakness. However, this complexity challenges our ability to place a

#### **6. Non-unique interpretations** degree of conductivity. Branching, complex features are often ineffectively propped, with risk of insufficient conductivity and continuity.

**7. Discussion of five deficiencies** 

the five issues described in this paper include:

compaction over time.

will be required to drain the available reserves.

The fifth thing we don't want to know about fractures is that it is nearly impossible to identify the deficiencies when analyzing production data from a single well. Figure 9 shows the production history (decline curve and cumulative production) from a single fractured interval, along with three plausible production matches. **6. Non-unique interpretations**  The fifth thing we don't want to know about fractures is that it is nearly impossible to identify the deficiencies when analyzing

Figure 9. With a single well, the production history can be matched with a nearly infinite combination of plausible fracture and reservoir descriptions [18, 19] **Figure 9.** With a single well, the production history can be matched with a nearly infinite combination of plausible fracture and reservoir descriptions [18, 19]

From a single decline curve, we cannot uniquely determine whether the fracture is short and "infinitely conductive," or long with more significant pressure losses. We cannot prove from a decline curve whether the fracture was simple or complex in geometry. We cannot prove whether the fracture conductivity was constant or degrading. Most engineers attempt to match the data with an analytic solution or a numerical simulator that presumes the frac is fully packed with proppant throughout, providing uniform and durable flow capacity without collapse of poorly propped sections. Note that with this approach an engineer can continue to reinforce any existing misconceptions. Fracs can be interpreted to be long or short. Disappointing well productivity can always be blamed on the geology – with no irrefutable proof that the fracture was insufficient. From a single decline curve, we cannot uniquely determine whether the fracture is short and "infinitely conductive," or long with more significant pressure losses. We cannot prove from a decline curve whether the fracture was simple or complex in geometry. We cannot prove whether the fracture conductivity was constant or degrading. Most engineers attempt to match the data with an analytic solution or a numerical simulator that presumes the frac is fully packed with proppant throughout, providing uniform and durable flow capacity without collapse of poorly propped sections. Note that with this approach an engineer can continue to reinforce any existing misconceptions. Fracs can be interpreted to be long or short. Disap‐

common expectations, even if the fractures are planar and fully propped.

Figure 8. Fracture complexity increases reservoir contact, but challenges our ability to create a durable proppant pack with sufficient hydraulic pointing well productivity can always be blamed on the geology – with no irrefutable proof that the fracture was insufficient.
