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Hydraulic fracturing of moderate to high-permeability reservoirs with short, highly conductive fractures is a technique often applied to improve well productivity through penetration beyond near wellbore damage. This paper investigates the effect of important fracture parameters (e.g., fracture half-length, fracture conductivity, and fracture-face damage) on the short-term behavior and long-term productivity of the well. The degree and extent of near wellbore damage, in addition to the fracture parameters, are varied in the sensitivity analysis. A case study from the Gulf Coast addresses the effect of these important parameters on the well response. It is evident the length and conductivity of a created hydraulic fracture have an important effect on the poststimulation performance of a well. Some of these fractures may be damaged. Damage to the proppant-pack has considerable effects, reducing the fracture conductivity. Generally fracture-face damage caused by fluid and polymer leakoff does not significantly alter long-term production, assuming the permanent reduction of absolute permeability is low (less than 90%) and provided the fracture bypasses the radial damage zone in the formation. When the fracture face damage is high (greater than 90%), early time well response is significantly impaired by the fracturing fluid cleanup process. This has implications on the timing of poststimulation pressure transient analyses. The modeled behavior and recommendations for the design of such tests are presented. Introduction A two-step-in-one fracture stimulation and gravel-pack procedure, has been emerging as a preferred well completion technique in soft formations and higher permeability reservoirs. Employing a technique known as tip screenout (TSO), the lateral fracture propagation is arrested, the fracture is inflated, and the resultant fracture is short and, presumably, highly conductive. A large fracture conductivity is required in higher permeability reservoirs while the fracture half-length is of secondary importance. Until recently, these treatments have encroached into extraordinary permeability ranges. Reservoirs with permeabilities of 2000 md or greater have been targeted. The execution of these treatments is burdened by considerable leakoff which is especially severe in higher permeability reservoirs. Filter-cake-building fracturing fluids (such as crosslinked polymer solutions) are employed to prevent the invasion, of polymers into the reservoir, normal to the direction of fracture propagation. These fluids effectively limit an invasion for reservoir permeabilities up to 50 md. For higher permeability reservoirs, crosslinked polymer solutions may invade the formation. Linear gels have been employed in a misguided attempt to reduce "fracture damage." The latter has been frequently confused. There are two distinct types of damage:proppant-pack damage inside the fracture, resulting from unbroken polymer chains, with a major impact on the created fracture conductivity, andfracture-face damage which refers to permeability impairment outside the fracture and normal to its. P. 237

Formation damage caused by fracturing fluid invasion along the fracture face has long been a concern in the petroleum industry. The results of a study on the effect of fracturing fluid cleanup and fracture face damage on gas production are presented. A numerical reservoir simulator is used to simulate (1) fracturing fluid invasion, (2) filtrate cleanup, and (3) gas production after the fracturing treatment. The reservoir properties used in the model are obtainedfrom an example well in the Cadomin formation from the deep basin area o northwestern Alberta. The rocklfluid interaction properties of this apparently "water-sensitive " formation, are determined in the laborator. Results of numerical simulation are used to match the actual pressure buildup test results. The cleanup process of the invaded fluid is demonstrated, as well as how gas production is affected by the permeability damage at the fracture.face. An algorithm combining the analytical and numerical methods to determine the fracturing fluid leakoff distribution profile is also summarized.

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