Critical Proppant Selection Factors
Fracturing proppant selection is crucial to optimizing well productivity. Recent studies have shown that many proppants often do not perform as expected when subjected to real-world downhole conditions of pressure, temperature, and fluid. Besides the traditional proppant selection factors of size, strength, and density, there are many other important factors to consider.
Proppant fines generation and the resulting migration in the fracture are considered to be one of the major contributors to poor treatment results and well performance. It has been noted by Coulter & Wells1 that just 5% fines can decrease fracture flow capacity by as much as 60%. Hexion’s advanced grain-to-grain bonding technology reduces proppant fines generation and migration through the proppant pack. The curable resin coating provides additional strength to individual grains, generates uniform stress distribution throughout the pack, and encapsulates any loose fines that may occur.
The Wet, Hot Crush Test™ procedure, recently developed by Hexion, more accurately simulates downhole conditions of temperature, pressure and fluid. A Wet, Hot Crust Test was conducted at 8,000 psi (55 MPa) to compare a curable resin coated sand (Hexion’s Prime Plus™ proppant) to both an uncoated frac sand and a lightweight ceramic. Prime Plus generated only 0.5% fines, significantly less than the other proppants. The fines generated by the lightweight ceramic (8.2%) and uncoated frac sand (23.9%) greatly decrease well production.
Proppant Pack Cyclic Stress
During the life of a well, numerous events such as well shut-ins during workovers, connections to a pipeline or possible shut-ins due to pipeline capacity lead to cyclic changes in fracture closure stress. Curable resin coated proppants resist these cyclic stress changes by forming a flexible lattice network that redistributes the stresses through the proppant pack, reducing individual point loads on each proppant grain. This feature leads to improved proppant pack integrity and well production.
Effective vs. Reference Conductivity
Traditionally, proppant performance has been measured using baseline or reference conductivity testing. Effective conductivity is a much more accurate measurement of downhole proppant performance. Unfortunately, the low flow rates during the baseline conductivity test do not simulate downhole flow rates. High flow rates downhole can cause proppant fines to migrate and severely decrease fracture conductivity.
To incorporate the effect of proppant fines, effective conductivity is calculated using the Coulter & Wells method to derate the published reference conductivity.
As you can see in the chart, utilizing effective conductivity to measure downhole proppant performance, Prime Plus clearly outperforms a lightweight ceramic by limiting proppant fines generation and migration.
Post treatment proppant flowback is a leading cause of well production decline, equipment damage, and well shut-ins for repairs. Proppant flowback can also cause loss of near wellbore conductivity and reduced connectivity to the reservoir.
Hexion’s curable resin coated proppants eliminate proppant flowback by forming a consolidated proppant pack in the fracture. This grain-to-grain bonding occurs under a combination of reservoir temperature and closure stress. This Stress Bond™ (SB) technology leads to increased proppant pack integrity and well production compared to uncoated and precured resin coated proppants.
Proppant Pack Rearrangement
Proppant pack rearrangement in the fracture can cause a significant reduction in propped width which can also lead to reduced fracture flow capacity and connectivity to the wellbore. As a well is produced, high flow velocities in propped microfractures may cause uncoated or precured proppant packs to shift or rearrange, causing the microfractures to narrow or possibly close completely.
Hexion’s curable resin coated proppants will prevent the proppant grains from shifting, keeping the microfractures propped open. This unique bonding technology provides additional proppant pack integrity, enhanced fracture flow capacity, and increased production during the life of the well.
Uncoated proppants and precured resin coated sands often deeply embed into softer formations due to the increased single point loading between the proppant grain and the soft fracture face. This leads to reduced fracture width and lower fracture flow capacity.
Lightweight ceramic proppants, in particular, embed deeply into soft shale formations. An additional issue with proppant embedment is the spalling of formation fines which can migrate and cause additional loss of fracture conductivity. With curable resin coated proppants, instead of just single grain point loading, there are multiple grains bonded together. This lattice network of deformable surfaces provided by the curable resin coating has shown to reduce embedment by redistributing stresses on the proppant pack within the fracture.
Proppant scaling is a geochemical reaction that occurs between an uncoated ceramic proppant pack and the formation in a wet, hot downhole fracture environment. While this reaction normally happens slowly in shallower formations, it accelerates under the higher pressures and temperatures. The result of proppant scaling is a severe loss of proppant pack porosity and permeability as fines and debris are created in the proppant pack. Uncoated lightweight ceramics can lose up to 90% proppant pack permeability in just a few days. Resin coated proppants drastically reduce the impact of downhole proppant scaling, resulting in improved fracture flow capacity and significantly higher long-term productivity.
There are other important proppant selection factors besides size, strength and density to consider. Hexion’s Oilfield Technology Group is committed to developing resin coated technology that addresses all these critical factors, providing improved proppant pack integrity, fracture flow capacity, and increased production during the life of your well. For more information, visit hexion.com/oilfield and waterfrac.com.
- Coulter & Wells, Journal of Petroleum Technology, June 1972.