The purpose of a hydraulic fracture treatment is to construct an areally extensive conductive proppant pack in the reservoir. Two key challenges are transporting the proppant all the way into the fracture and the resulting pack remaining highly conductive for the life of the well.

Sand Figure 1

FIGURE 1. An advanced ceramic proppant (top left) is more spherical and smoother than conventional ceramic proppants (top right). The cross section of a single bead of the engineered proppant (bottom left) shows the hollow core and microporous shell compared with the numerous large pores, which weaken the conventional ceramic proppant (bottom right) (Images courtesy of Oxane Materials).

In low-permeability reservoirs hydraulic fracture design focuses more on creating fracture length than conductivity because surface area strongly influences production. Surface area is more important in ultra-low permeability reservoirs such as shale. Hydraulic fractures are often designed to promote development of a fracture network because surface area in a network of created and natural fractures is much larger than in a simple planar fracture.

In a 20-well field test OxBall, an advanced ceramic prop-pant, was shown to improve cumulative 12-month production by 20% relative to conventional intermediate-strength proppant (ISP).This improvement is a result of the properties of this engineered proppant. The beads are lighter due to a hollow core and are strong because they are ceramic. For example, an engineered proppant bead with the strength of typical ISP is 20% lighter than ISP with roughly the same density as sand. In contrast to conventional top-down ceramic proppant manufacturing, a bottom-up process is used to coat ceramic cores with layers of mixed-metal oxide. The process yields beads consistent in strength, size, sphericity, and surface smoothness. Consistency is achieved by controlling the internal porosity of the individual beads (Figure 1). The properties of these engineered beads can translate into superior proppant transport and conductivity in slickwater fracturing.

Transport and conductivity

Historically, proppant transport into hydraulic fractures was managed by pumping viscous fluids in which prop-pant grains settled very slowly due to gravity. Ideally, very little proppant settled into a bank at the bottom of the fracture during pumping. After pumping when the fracture closed, the proppant was held in place by the closure pressure exerted by the reservoir rock.

In the modern era thin fluids such as slickwater are used to increase hydraulic fracture surface area and reduce cost. Unfortunately, these fluids lack the viscosity to prevent rapid density-driven proppant settling. The much lower density of the engineered beads increases the distance the proppant flows into the fracture before falling into the bank at the bottom of the fracture.

Hollow ceramic beads have a higher coefficient of restitution than typical ceramic beads and a much lower propensity to cluster when settling. Proppant transport in slickwater fractures is governed by very different physics. Instead of a small bank at the bottom of the fracture, much of the proppant quickly forms a dune similar to a sand dune in the desert. The proppant dune advances along the fracture by saltation, in which particles on the surface of the dune are repeatedly resuspended into the flowstream and carried a little further before redepositing.

The properties of the engineered proppant are key to transport in this environment. The spherical beads exhibit a lower friction coefficient than conventional ceramic proppants, resulting in a shallower dune. A given volume of proppant will travel farther into the fracture. For example, with the lab-measured difference of 23° vs. 30° angles of repose, these beads will move almost 30% deeper into the fracture, even if all the other properties were identical.

The active surface layer of a dune of the beads is thicker because the beads are lighter than standard ceramic prop-pants and the coefficient of restitution is greater. The beads are more easily resuspended and swept higher into the flowstream, which carries the beads further before redepositing. The combined effects of friction, density, and coefficient of restitution thus result in deeper penetration of the proppant beads into the fracture.

Sand Figure 2

FIGURE 2. The offset well production is compared with OxBall production over a 12-month period. Production scale is not shown per operator’s request.

The conductivity of a proppant pack is key to production. Conventional wisdom suggests that conductivity is not very important in unconventional reservoirs because even poor pack permeability is much higher than the reservoir permeability – the so-called “infinite-conductivity fracture.” However, it has been shown that good conductivity is required even far from the wellbore. In that region the fracture is so narrow that every grain counts. Near the wellbore, the fracture must be conductive to avoid choking the oil and gas streaming from the entire created fracture network into the limited area around the wellbore.

Standard conductivity tests demonstrate how the properties of the individual beads of the engineered proppant translate into better performance, especially at higher stresses where the conductivity is as much as 75% higher than conventional ceramic proppants.

Field test results

The ultimate test of any new stimulation technology is the impact on the production of oil and gas. By the end of March 2013 the engineered proppant had been pumped into 34 wells for five different operators by five different pumping companies. One operator in the Permian basin performed a 20-well field test specifically to determine the benefit of using the engineered proppant. Ten wells were stimulated with OxBall and 10 direct offsets with conventional ISP. As a result of numerous serious operational issues on one job, only nine pairs could be used for analysis.

For three of the pairs, the field operation went very well, and the wells were in comparable locations. Production results could be compared directly. The production improvement from using the engineered proppant peaked around 20% at three months, dropped as low as 10% at 12 months, and then began to improve. At 16 months the cumulative production from the wells with engineered proppant was 14% higher than that from the offset wells.

Operational changes to the job schedule affected the three-month results. Over a longer timeframe of six to 12 months, interference was observed between closely spaced wells so that wells in the corner of a section performed better than wells on the edges, which in turn outperformed interior wells. A full statistical analysis adjusting for these effects isolated the effect of the proppant as an average of 20% improvement in 12-month cumulative production. In Figure 2 the offset well production is compared with the OxBall production, adjusted for the effects of well location and proppant stage volume variations. The benefit of pumping the engineered proppant ranges from a low of 7% to a high of 34% in these wells.

References available.