Work reported in this paper shows that fracture-pack permeability and conductivity are impacted by the mobility of formation-generated fines plugging under high-stress and high gas flow-rate conditions. The authors examine two approaches to (1) prevent formation fines from entering the proppant pack and (2) provide higher sustained fracture-pack permeability and conductivity under severe production conditions. The paper further shows that significant improvements can be obtained in both the short term and the long term, and how these improvements can be used to provide sustained gas production.

The results of laboratory testing are reviewed in detail, including the mechanisms by which fines are immobilized and the conductivity is maintained. The mechanisms involve an on-the-fly, direct coating of proppant with surface-modification agents (SMA) just before the proppant is blended with the carrier fluid. The chemical properties of the SMA can be varied widely to meet downhole conditions and production flow rates. The treatment renders the formation sand and fines immobile so that migration and plugging do not occur. In addition to fines stabilization, SMA can be formulated using liquid resin to consolidate the proppant pack, making it useful in controlling proppant flowback at high production rates, and in providing long-term pack stability. The effects of non-darcy flow are also examined and compared to baseline data.

Field studies are reviewed to evaluate how actual productivity can be affected, both short-term and long-term, by controlling fines damage to provide long-term fracture conductivity.


The importance of fracture conductivity and its effects on well productivity are well understood in the petroleum industry.1 Laboratory testing procedures are well documented and databases are available to the industry to help design engineers optimize the fracture treatment designs in terms of fracture geometry, proppant concentration, and proppant type. In spite of the availability of advanced design tools and reams of conductivity test data, post-treatment performance in many wells seems to suggest that the effective fracture length may be shorter than expected. The shorter fracture lengths may be the result of fluid cleanup issues or loss of fracture conductivity due to fluid residue such as filter cake or formation embedment of proppant. Effective fracture length can be affected by broken fluid properties and the conductivity in the fracture.2,3

Increased Fracture Conductivity

The impact of increased fracture conductivity in lower-permeability reservoirs may be argued; however, improved fracture cleanup and longer effective fractures should be a direct result of the increased fracture conductivity. In the simplest form, the effective fracture length (wellbore to tip) can be estimated using the following equation:

  • Cr=wKf/(pXeffK)

Cr=Conductivity ratio

wKf=Fracture conductivity (md ft)

K=Reservoir permeability (md)

Xeff=Effective fracture length (ft)

The effective length can be approximated by (1) solving the above equation for the effective length and (2) setting the value of the conductivity ratio to 10. This process defines the infinite conductivity fracture length, which provides a reasonable estimate of effective fracture length when fracture cleanup is taken into account.1–4 In this case, the effective fracture length is defined as the length of the created fracture that actually cleans up and contributes to production.

This content is only available via PDF.
You can access this article if you purchase or spend a download.