In low-permeability reservoirs, hydraulic fracture design focuses more on creating fracture length than conductivity because hydraulic fracture surface area strongly influences production. In ultra-low permeability reservoirs such as shales, hydraulic fractures are designed to create complexity because the surface area in a network of created and natural fractures is much larger than in a simple planar fracture. Thin fluids are usually used to promote complexity and reduce cost. These fluids severely limit proppant transport to the fracture tips because conventional proppant forms an immovable bed at the bottom of the fracture.

Three assumptions are often made regarding required conductivity, proppant transport mechanisms and cost trade-offs in unconventional reservoirs, namely:

  1. Proppant pack conductivity is unimportant because hydraulic fractures in ultra-low permeability formations are effectively infinitely conductive.

  2. In thin fluids such as slickwater, proppant settles much faster than Stokes Law implies, and it is difficult to transport proppant far into the fracture, unless later proppant rides over a bank of previously-settled proppant.

  3. Ceramic or advanced ceramic proppants don’t improve production enough to justify their cost.

These assumptions have a significant impact on well performance, and are often incorrect.

A methodology to determine the optimum conductivity around a horizontal wellbore is presented. This analysis accounts for the converging flow in a fracture connected to a horizontal wellbore, which requires a much higher conductivity than a comparable fracture connected to a vertical well to avoid limiting production.

Some of the physical properties which affect proppant pack conductivity are discussed and quantified. Small-diameter advanced ceramic proppants (50/60 and 60/70) are demonstrated to maintain conductivity much better than larger diameter conventional ceramic proppants under high stress. This reduces the need to pump lower conductivity materials to achieve transport deep into the fracture.

The three mechanisms of proppant transport in thin fluids (suspension, saltation and reptation) are described, and related to specific physical properties of the proppant beads. The effect of the coefficient of restitution on the development and transport of the dynamic layer above the proppant bank is quantified. Some aspects of fracture design which take advantage of small proppant beads and the saltation mechanism are presented.

Prior analysis of oil production results from field trials of an Advanced Ceramic Proppant are extended to the gas and water production from the same trial. Although both gas and water production are correlated with oil production, other data shows that the gas is associated, and the water is most probably returned load water. In this field trial, wells treated with advanced ceramic proppant increased oil and gas production by 20% and 38% respectively over wells treated with conventional ceramic proppant.

An economic model to quantify the benefit of better production based on a simple type curve and average well cost information is described. The Net Present Value, Internal Rate of Return and Payback Period for a typical Duvernay well are calculated. The example demonstrates that advanced ceramic proppant has the potential to increase Net Present Value by 35%, reduce payout time by 20%, and increase the Internal Rate of Return of the well from 43% to 54%.

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