Self-Suspending Proppant Transport Technology Increases Stimulated Reservoir Volume and Reduces Proppant Pack and Formation Damage

Self-suspending proppant technology, a hydrogel polymer wrapped around a sand or ceramic substrate, resists settling in a low-viscosity fluid to uniformly distribute proppant throughout the fracture. The fluid remains in-zone to increase the stimulated reservoir volume. With this new technology, oil and gas production increases.

This technology eliminates compromises the industry has faced for decades. Because proppant falls out of the fluid before reaching the fracture tip, engineers have had to increase fluid viscosity and/or pumping rates, in addition to decreasing proppant mesh size or proppant density. These compromises increase completions cost and reduce conductivity.

With self-suspending proppant technology, fluid sweeps are eliminated because proppant maintains efficient transport characteristics and forms a higher, more uniform settled bed height compared with proppant transported by conventional gel or slickwater fluid systems. Pumping time is reduced because of the higher capacity to carry proppant compared with slickwater. Fewer fluid additives are required because less fluid volume is needed.

In addition to better proppant transport, this technology reduces proppant pack and formation damage. After breaking the polymer system and during fluid flowback, little to no residue remains. Further, according to test results from an independent laboratory, this new technology does not damage the proppant pack and formation with fluid additives, resulting in maximum regain conductivity and retained permeability. Typical frac fluid additives that support proppant transport can damage proppant pack conductivity and formation permeability by as much as 70% and 60%, respectively (Bilden, Fletcher, Montgomery, Guillory, and Allen 1995).

Two field trials show how the application of self-suspending proppant technology can increase stimulated reservoir volume and increase well production. In a Mississippian Lime liquids-rich play, self-suspending-proppant-coated 20/40 Northern White sand increased 18-month cumulative BOE 45% compared with the uncoated 20/40 Northern White sand in the offset's conventional slickwater design.

In an Escondido formation gas play, an operator compared a 46% self-suspending proppant tail-in with a simplified slickwater design. The technology boosted 60-day gas production by more than 55% while decreasing pumping time and water consumption with fewer fluid additives.

The shear-resistant polymer ensures greater drainage by traveling farther in a thin fluid for a substantially increased propped fracture area. A clean polymer break leaves the proppant pack and formation without fluid damage so hydrocarbons can flow freely.