Proppant settling occurs during hydraulic fracturing operations when the fluid viscosity falls below the critical threshold required to suspend proppant. The settling can reduce the deliverability of the fracture, negatively impacting productivity.
In slickwater applications, the viscosity of the base fluid is inadequate to provide proppant transport. In tight gas applications with conventional crosslinked fluids, the fracturing fluid is designed to break shortly after pumping. The fracture remains open for hours, and a low-viscosity fluid remains that is unable to suspend the proppant.
Tailored, fiber-based fracturing fluid
FiberFRAC fiber-based fracturing fluid technology decouples proppant transport from fluid viscosity. The technology creates a fiber-based network within the fracturing fluid, providing a mechanical means to transport, suspend, and place the proppant. Because the proppant transport then no longer relies on fracturing fluid viscosities, it can be tailored to reservoir conditions to optimize fracture geometry. If fracture height growth is a concern, a low-viscosity fluid can be used, even at high temperatures, while still maintaining good proppant transport.
In addition to fracture height containment, the retained proppant-pack permeability can be significantly increased because of the lower polymer loading required. Laboratory testing has shown that decreasing the polymer loading by 40% can increase retained permeability by 24%. When less polymer is used, more of the propped fracture contributes to production, yielding a longer effective fracture half-length.
APPLICATIONS
■ Hydraulic fracturing operations on tight gas wells
■ Low-permeability environments with extended fracture closure times
■ Temperature ranges between 140 and 345 degF
■ Slickwater fracturing fluid treatments
■ Crosslinked polymer fracturing treatments
BENEFITS
■ Improved production rates
■ Greater reservoir drainage efficiency for lenticular reservoirs
■ Increased retained proppant-pack permeability
■ Optimal dimensionless fracture conductivity
■ Less fracture height growth
FEATURES
■ Proppant transport decoupled from fluid viscosity
■ Enhanced proppant distribution fibers that degrade over time
■ Lower-viscosity fracturing fluid extended temperature range
■ Lower polymer loadings
Case study: FiberFRAC fluid delivers 7 times greater gas production for PEMEX well
Comparison and evaluation of fracturing treatments
In the Arcabuz field of the Burgos basin, a better fracturing treatment was needed. PEMEX decided to evaluate the performance of FiberFRAC fiber-based fracturing fluid technology by comparing it to conventional fracturing applications in two wells with comparable reservoir characteristics.
Dramatic differences in fracturing treatment results
The FiberFRAC fracturing treatment was used for the first well, Arcabuz 316. It consisted of 90,718 kg [200,000 lbm] of ceramic proppant and 2,268 kg [5,000 lbm] of resin-coated ceramic proppant pumped at a rate of 35 bbl/min. After 1 week of flow, the production was 2.2 MMcf/d of gas and 30 bbl/d of water at 34.5-MPa [5,000-psi] wellhead flowing pressure.
A conventional fracturing stimulation treatment was performed on the comparable well, offset Arcabuz 307. The fracture treatment used 90,718 kg [200,000 lbm] of ceramic proppant and 22,680 kg [50,000 lbm] of resin-coated ceramic at a pumping rate of 35 bbl/min. Polymer fluid was injected at 3,595 kg/m3 [30 lbm/gal] with no fiber added. After 1 week, Arcabuz 307, interval Wilcox 4, showed production of only 300,000 cf/d of gas with 360 bbl/d of water at 5.2-MPa [750-psi] wellhead flowing pressure. Additionally, a considerable drop in pressure at the final treatment stage suggested excess height growth in zones of high water saturation.
The WellWatcher real-time reservoir and production monitoring system helped to simultaneously analyze production decline over time and study fracture geometry, enabling a direct comparison of production results between the two wells.
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