(Tech Connections Column, April 2006, American Oil and Gas Reporter)

Since the first hydraulic fracture treatment in 1949, hydraulic fracture stimulation methods have done more to increase recoverable reserves than any other technique, particularly from natural gas wells. An analysis performed by the Department of Energy indicates 75-79 percent of new gas production from the onshore lower-48 will be produced from hydraulically fractured wells.

A PTTC workshop captured some key factors in designing for optimum results. A basic hypothesis in hydraulic fracturing is that production is a function of effective fracture length and conductivity. High-viscosity fluids carrying high proppant concentrations should provide more stimulation than water fracture treatments, provided the treatment stays within zone, the fracture face is not severely damaged, and the fracture fluid breaks and cleans up properly.

Building an accurate mechanical earth model is essential. Well bore image and dipole sonic logs provide important data. Logs must be calibrated with core data. Permeability/porosity relationships and in-situ stress contrasts are important. Evaluate many design alternatives on the computer–it is much cheaper there.

Geomechanics indicate what can be achieved. Key parameters are stress, modulus and leak-off. Reservoir permeability is a critical parameter. Permeability can be measured with prefrac modified fracture injection tests. MFITs break down the formation, and set volumes are injected at different rates; then the well is shut in and pressure decline is monitored.

Dimensionless conductivity (Fcd) is the ratio of the ability of a fracture to carry gas to the well to the ability of the formation to feed gas into the fracture. In conventional reservoirs, one designs to achieve Fcd of 2. For tight gas sands, one needs an extra margin of safety for cleanup, designing for a range of 8- 10. There are multiple factors that impact conductivity, including gel residue, damaged proppant, formation fines, and degraded proppant. A mere 20 percent porosity reduction may result in a 60 percent loss in permeability. New evidence indicates that proppant pack porosity (and thus conductivity) degrades with time. Coating proppants with resins or surface modifying agents reduces degradation.

There is widespread use of water fracs rather than gel fracs. Some contend this is not to achieve better results, but because water fracs cost less and achieve production comparable to underperforming gel fracs. If selecting treated water, one has decided that fracture conductivity is not important. One can use less proppant, which should be smaller so it will be transported farther. Many operators now employ hybrid treatments.

Operational attention is important. Everything about the fracture treatment should be “physically” measured and recorded. Step-down tests can quantify near-well bore friction. Minifracs provide information on fluid efficiency, leak-off and fracture closure pressure. Monitor pressure fall-off after the treatment. Immediate flow back accelerates fracture closure, which reduces undesirable proppant settling.

There are sweet spots in any reservoir. Data confirm that two-thirds of cumulative production comes from a third of the wells. How can one identify production potential before treat-ment? A tight gas reservoir can exhibit a permeability distribution differing by two orders of magnitude. Log interpretation and core data to accurately measure the porosity and permeability range in a well are critical. Knowing that range allows a fracture treatment to be designed for the higher permeability intervals.

BJ Services has developed an ultralightweight proppant made of walnut hulls impregnated and encapsulated with resins. It settles less and travels farther, which increases the propped area several fold. BJ reports more than 1,800 wells have been treated–many of them slick-water fracturing applications. Performance data in several basins and formations indicate significant increases in production.

An advance by Schlumberger is ThermaFOAM, a foamed carbon dioxide-base fluid. It is cleaner than conventional fluids and breaks faster, shortening time to sales. About 60 jobs have been pumped. Schlumberger also has developed FiberFRAC technology, which relies on a mechanical, fiber-based network to transport proppant. The mechanical fibers degrade and disappear. More than 150 jobs were pumped in 2005.

Halliburton offers CobraMax and SurgiFrac options for pinpoint stimulation. With CobraMax, holes are jetted in the casing, the frac is pumped, sand is filled, and operations move uphole to the next zone. Describing a Chevron program in California’s Lost Hills Field, Halliburton notes that results from more than 30 wells indicate completion costs per barrel of oil equivalent are down by almost half compared to conventional perf and plug, limited-entry fracturing. This technology also is being used in horizontal wells.

There is a final caution from the experts. There is an image of a single fracture growing as modeled, with fluid and proppant moving in a piston-like manner. Industry is increasingly recognizing that real-world fractures can be much more complex. These off-balance (complex) growth tendencies, which cause performance to be less than predicted, can be reduced by adjustments in treatment design, perforating scheme and job execution..