This study was performed to examine fracture conductivity using different core face materials ranging from unconsolidated sand to very hard consolidated sandstone. Two approaches were investigated 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 well production. Laboratory results show that with weakly unconsolidated rock, the conductivity values are much lower than one would expect based upon test results from Ohio sandstone (moderate hardness) core face material. There is a definite trend in the measured fracture conductivity that is related to the mechanical properties of the rock. The chemical properties of the liquid surface-modification agent (SMA) can be varied widely to meet downhole conditions and production flow rates. To minimize formation fines from entering the proppant pack, the proppant is directly coated "on the fly" with an SMA just before the proppant is blended into the carrier fluid. SMA coatings placed on the proppant provide a stable interface between the formation and proppant pack, resulting in dramatic improvement in fracture conductivity. In unconsolidated rock, minimizing the intrusion of formation material into the proppant pack and maintaining pack permeability were observed. When testing on hard rock, increased porosity of the proppant pack and stabilization of the formation face provided improved performance in both high- and low-stress applications.
Formation fines are known to cause severe formation damage during production, limiting the potential production of the well. Many factors contribute to the migration or movement of formation fines.1,2 Various techniques have been developed in the industry through the years for examining fines-stabilizing solutions to overcome the effects of fines migration.1,3 Acidizing has been used to dissolve fines particulate for "unblocking" and enlarging pore space in the formation near the wellbore to increase the permeability of the formation. Other chemical treatments, including (1) clay-stabilizing surfactants as part of the completion fluids, or (2) polymers in remedial operations, have been applied to minimize fines migration and enhance the well productivity.4 These treatments commonly require the treatment fluids to be injected deep into the formation matrix, allowing the surfaces of the fines and pores to be in contact and interact with the treatment fluid. Large volumes of treatment fluid are often required to achieve the desired results. Most such treatment fluids provide only temporary solutions, because they tend to desorb with time and production of fluids from the well. It has been a paradigm in sand-control completions that it is better for the fines or loose particulate to migrate through the proppant pack, whether the proppant pack is in a propped fracture or in the annulus behind the sand screen. This is wishful thinking; the reservoir formation provides an infinite supply of fines and loose particles that continue to enter the pack with the fluid production.
