Post stimulation proppant flowback can be a serious problem after the hydraulic fracturing process and can cause a variety of issues like: reduced fracture propping resulting in decreased conductivity and hydrocarbon production;erosion related damage to surface and downhole equipment; and increased costs in dealing with recovered proppant disposal. To address the concerns related to proppant flowback, various technologies, including chemical, mechanical, and engineering design have been employed. A common and long term commercial approach is to apply a resin to the surface of the sand. However, resin coatings can be costly relative to the cost of the sand substrate, often doubling or tripling the cost of the sand substrate to which they are applied. Additionally, resin coated proppants often need to be activated with exposure to temperature and pressure. The requirement for additional chemical activators at lower reservoir temperatures can also add additional cost to the treatment. Furthermore, resin coated sands are typically manufactured near a sand mine and then shipped to remote well locations. This offers another layer of logistical complexity to bringing large volumes of sand to a site or often multiple types of sand and thus can add additional costs. In some cases, on-site or near-site manufacturing of resin coatings is possible, but again at an additional cost. A proppant flowback control measure which is cost-effective and can function over a wide range of reservoir conditions would be advantageous to the hydraulic fracturing process.
A new technology for proppant flowback control was previously presented where chemically modifying the proppant surface with the proppant consolidation additive (PCA) can induce a strong capillary attraction among proppant grains leading to proppant agglomeration (Lu et al., 2016). This study serves to further examine this sand surface modifying chemical. Additional experimental results will focus on conductivity measurement of surface treated proppant and flow resistance tests of treated proppants relative to untreated proppants at varying conditions. The field performance of more than 50 wells in western Canada in terms of proppant flowback control using thisnewly developed technology will also be presented. A discussion of field application and results in several scenarios will demonstrate the correlation of the laboratory experimental results to actual field performance.
Compared with untreated either Tier 1 or Tier 2 proppant, the surface treatment of proppant increases flow resistance under all the tested confining pressure, also, noticeable increase of proppant conductivity under high confining pressure was observed, which is an advantage of the surface treatment of proppants. The field performance data show that this newly developed technology gives similar or better results relative to resin coated proppants in terms of proppant flowback control. This technology demonstrates the following advantages: 1) it can be applicable to either Tier 1 or Tier 2 proppant; 2) it can be easily applied on-the-fly to sand during a fracturing operation, either as the tail in sand stage, alternating during the entire stage, or being sprayed on all the sand stage, which makes it flexible for operators to design proppant flowback control and to ease the logistics of managing proppant delivery to location as well; 3) it perfroms under a wide range of reservoir conditions because it is independent of reservoir pressures and temperatures.