Rapid loss of fracture conductivity after hydraulic fracture stimulation has often been attributed to the migration of formation fines into proppant pack or the generation of fines derived from proppant crushing. Findings presented in this paper suggest that diagenesis-type reactions that can occur between proppant and freshly fractured rock surfaces can lead to rapid loss of proppant-pack porosity and loss of conductivity. Generation of crystalline and amorphous porosity filling minerals can occur within the proppant pack because of chemical compositional differences between the proppant and the formation, and the compaction of the proppant bed due to proppant pressure solution reactions.

This damage mechanism is applicable to all propped, fracture-stimulated wells; however, it is more significant in high temperature and high stress wells. It provides a possible explanation for the difference often observed between reservoir simulation of production after fracturing and actual production.

Studies indicate as little as 25% of the initial proppant-pack porosity may remain after only 40 days at 300°F and 6,000-psi closure stress. The rate of porosity loss can be influenced by the surface treatment of the proppant, which indicates that some control of this process may be accomplished.

Significance of this discovery has great impact on the economic life of a fracture-stimulation treatment. It affects the choice of proppant composition and post-fracture cleanup procedures, and adds an additional dimension to the appropriate laboratory determination of fracture conductivity that might be expected with the use of a particular proppant.


Lehman et al.[1] reported that the use of surface-modification agents (SMA) to coat proppants used in propping hydraulic fractures resulted in sustained and more uniform production from wells. Fig. 1 taken from that publication shows the production decline curves from some of their data, and it does appear to show a significant change in decline rate compared to the use of untreated proppant.

Initial use of this type of SMA treatment was promoted as a method to increase the conductivity of proppant owing to its ability to prevent close packing of the proppant, which can result in increased porosity and permeability of the pack by rendering the proppant surface tacky. Subsequent studies indicated that its use provided proppant-pack protection from fines infiltration and migration. This mechanism has been employed to explain the observations that sustained production results from the use of SMA on proppants. This is further substantiated by long-term results obtained in a single field study known for fines production problems. That both mechanisms are active has been well established through laboratory studies, but they alone do not completely explain the reduction in production decline rate as reported.

A field study of SMA-treated proppant was reported to the Arkansas Oil and Gas Commission 2004 CBM Workshop that disclosed long-term results on gas production. These were CBM wells in the San Juan Basin that typically required refracturing each year to produce at an economical rate. With the SMA-treated proppant, no refracs have been required, and as shown in Fig. 2, production has remained essentially constant for 5 to 6 years. This longevity was initially attributed to prevention of fines invasion into the proppant pack; however, it is possible that there are additional mechanisms operational.


Hydraulic conductivity is simply the ability of a conduit to transmit a fluid. It is a function of the fluid properties and the conduit geometry. It is determined by measuring the pressure drop and fluid rate for a specific fluid through a conduit of fixed length with respect to the cross-sectional flow area. If the conduit is a pipe with fixed length, conductivity is usually presented by friction-drop-per-length tables for a specific fluid and is calculated using the Darcy-Weisbach equation. The key parameters in determining any hydraulic conductivity are conduit geometry, fluid rate, pressure drop, and fluid viscosity.

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