Of utmost importance, those completing low permeability marginal wells must recognize that it is engineering intensive. A basic hypothesis in hydraulic fracturing is that production is a function of effective fracture length and effective fracture conductivity. Accepting this, 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. Several speakers noted that industry needs improved fluids (breakers) for reservoirs in the 200 - 250 °F range. Other areas needing attention are better completion methods for thick multi-zone intervals, log-core correlations in tight sands, better understanding of oriented perforating, rapid analyses of well performance of tight gas sands, and models for naturally fractured reservoirs. More field data collection, demonstration R&D projects and better technology transfer are part of the picture.

Building an accurate mechanical earth model is essential to hydraulic fracturing success. Logs provide important well data. Taken together, wellbore image and dipole sonic logs provide key information about natural fracturing and fracture orientation. It is critical that logs be calibrated with core data. Fortunately, key parameters in the mechanical earth model do not vary widely in a given geographic area, so one doesn't need to core extensively. The most important correlation to develop is the relationship between permeability and porosity as a function of lithology. The second most important correlation is to determine values of in-situ stress in each rock layer above, within and below the pay zones. One can and should make multiple modeling runs, playing with the variables to learn which are important and the effect they have. Post-treatment analyses help refine the mechanical earth model.

When it comes to treatment design, geomechanics tell you what you can achieve. Key parameters are stress, modulus and leak-off. Reservoir permeability tells you what you want to try to achieve. One can measure permeability with pre-frac Modified Fracture Injection Tests (MFIT). In MFITs, the formation is broken down, set volumes are injected at different rates, then the well is shut-in and pressure decline monitored.

It is "effective" fracture dimensions (length and width), not just created dimensions, that are important. Long fracs that don't stay propped or open achieve nothing. Achieving and maintaining conductivity in the

fracture is essential. There are multiple factors that impact conductivity, including gel residue, damaged proppant, formation fines and degraded proppant. Just a 20% porosity reduction may result in a 60% loss in permeability. Operators often finish off treatments with small volumes of high proppant concentration, striving to achieve very high conductivity in the very-near-wellbore region.

New evidence indicates that proppant pack porosity (and thus conductivity) degrades with time. Conventional proppants are subject to embedment and crushing, which creates fines. The larger the proppant, the higher the rate of degradation. Data show that coating proppants with resins or surface modifying agents reduces degradation.

In several areas, industry has moved to waterfracs rather than gel fracs for tight gas sands. Some contend that this is not because waterfracs give better results, but because waterfracs cost less and achieve production comparable to underperforming gel fracs. If choosing treated water, there must be some in-situ stress contrast, a vertical Fcd > 2 and some residual un-propped fracture width. 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 further. Many operators are moving back towards conductivity, employing hybrid treatments with treated water and linear gels.

Hydraulic fracture treatments are usually a major portion of well costs, so operational attention is warranted. Know that potential problems are compounded with large volume, high rate jobs mixed on-the-fly. Everything about the treatment should be measured and recorded, and that means "physically" measuring inventories during and after the treatment. Step-down tests can quantify near wellbore friction (tortuosity/perforation friction). Minifracs provide information on fluid efficiency, leakoff and fracture closure pressure. Monitor pressure falloff after the treatment. Immediate flowback accelerates fracture closure, which reduces undesirable proppant settling. It is common practice to flow-back at 2 - 3 BPM. When gas starts coming back, choke size should be reduced to maintain flowing

bottomhole pressure at 50% of reservoir pressure.

Everyone knows it—there are sweet spots in any reservoir. Data from multiple fields confirm the fact that two-thirds of cumulative production comes from roughly one-third of the wells. To avoid spending too much on what will be poor wells, how can one identify production potential prior to the treatment? 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 is critical. Knowing that range, design a fracture treatment for the higher permeability intervals.

BJ Services (BJ) has developed an Ultra-Lightweight Proppant (ULWP) made of walnut hulls impregnated and encapsulated with resins. As most commonly developed, this ULWP has an apparent specific gravity less than half that of conventional sand-based proppants. Being lighter, this ULWP settles less and travels further, which increases the propped area several fold. BJ reports that over 1,800 wells have been treated with many being slickwater fracturing applications employing near neutrally buoyant slurries. Performance data in several basins and formations indicate significant increases in production even though treatments used significantly less proppant.

A recent advance by Schlumberger is ThermaFOAM, a foamed CO₂ base fluid using a synthetic polymer. ThermaFOAM CO₂ fluids are cleaner because lower polymer loading is possible and no crosslinker is required. Faster cleanup leads to reduced time to sales, which adds to the economic benefit. Out just a short time, more than 60 jobs have been pumped in highly depleted to normally pressured reservoirs. Production data from Wilcox and Olmos sand treatments show a marked improvement in productivity. Schlumberger also described experience with its FiberFRAC technology. FiberFRAC relies on a mechanical fiber-based network for proppant transport. This mechanical system leads to longer effective fracture half-lengths. The mechanical fibers degrade and disappear. More than 150 jobs were pumped in 2005. Examples from the Cotton Valley in East Texas, Wilcox in north Mexico, Barnett Shale and Jonah Field demonstrated definite productivity improvements.