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Enhanced Flow Applications

Injection or extraction of fluid (liquid or gas) from a well typically involves a sand or gravel body that connects the well screen to the formation material. This is true both for conventional wells completed with a sand pack, and for wells that intersect sand-filled hydraulic fractures. The primary difference between these configurations is the geometry of the sand body, and the resulting interfacial area between the sand and formation material. A typical 5-ft-long, 8-inch-radius sand pack has an interfacial area of 11 ft. By contrast, the sand-filled portion of a typical 10-m-radius hydraulic fracture has an interfacial area of 630 ft, which is 60 times greater! Fluid flux through a given cross sectional area between the formation and fracture sand is a function of induced pressure differential and formation permeability. The increase in total flow rate to or from a hydraulically fractured well results from increasing the formation area available for flow.

Diagrams showing differences in induced flow patterns while injecting into fractured wells and conventional wells. Fracture thickness is exaggerated for illustrative purposes.

Assuming a low permeability formation material, the pressure drop required to induce fluid flow through fracture sand is much less than that required to force fluid from the sand into the formation. Therefore, injected fluid will tend to completely fill the fracture and enter the formation across the entire upper and lower surfaces of the fracture. However, due to the fact that flowlines diverge at the fracture tip, the fluid will tend to preferentially enter the formation along the outside perimeter. This phenomena can be observed when plotting resulting gas saturation data from air sparging simulations. This type of flow pattern significantly increases the radius of influence for any type of injection or extraction well.

Gas saturation distribution results from air sparging simulations. Gas tends to enter the formation near the tip of hydraulic fractures, significantly increasing ROI.

There are other beneficial aspects resulting from emplacement of sand filled hydraulic fractures that enhance total flow rate and zone of influence. As fractures propagate through the formation they have the potential to intersect naturally occurring high permeability structures, depositional sand lenses or natural fractures for instance. The natural structures are incorporated into the overall fracture flow scheme when this occurs, which further increases flow potential and volume of the treatment zone. The sand pack of a conventional well tends to remain isolated from these structures, and therefore does not benefit from their presence.

Well skin is another attribute that often hiders performance of conventional wells. Sand-filled hydraulic fractures cut through any pre-existing well skin that may have been produced during well installation. This completely eliminates the large pressure drop that occurs along the perimeter of the borehole when well skin is present. Eliminating the effect of well skin can be extremely beneficial even in formations with relatively high permeability, where well skin has been produced by smearing material from overlying low permeability layers.

Subsurface pressures measured at different radii during SVE in conventional and hydraulically fractured wells.

All of these factors associated with installation of hydraulic fractures combine to provide flow rate and zone of influence benefits for active environmental remediation systems. These types of benefits can be observed when plotting data collected from SVE wells for which our services have been implemented.

Mass flow rates into conventional and hydraulically fractured air sparging wells at the same site. Tests involved increasing injection pressure by 2 psi every 10 minutes.

Contaminant mass recovery rates from wells at an SVE site. Solid bands represent the average for each well type. Increases in mass recovery are attributable to increases in gas volumetric flow rates.