TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe poorer-than-expected performance of some fracturing treatments has been an issue for decades. Considerable effort has been devoted to improved modeling of fracturing treatments so that improved expectations can be provided. Fracturing fluids have been modified to enhance cleanup. Proppant conductivity studies have lead to a better understanding of fracture performance. Yet, there are still many treatments, particularly in low-permeability gas wells, that defy efforts to clean up quickly and to produce at the expected rates. This paper revisits the question of whether fracture face damage is an issue in the subsequent performance of a gas well. It will be demonstrated that the landmark paper by Holditch 1 has been misquoted for 25 years. A numerical simulator has recently been written that has reproduced the earlier work, but also expands on it by demonstrating the physical mechanisms by which fracture face damage can reduce gas production and accelerate water production. The simulator includes relative permeability curves for both gas and water, and capillary pressure functions. The role of Laplace pressure, or capillary pressure, will be highlighted in the explanation of how fracture face damage can cause significant loss in well productivity. In addition, the role of relative permeability to gas will be highlighted as to how it ultimately leads to decreased gas production and increased water production when the fracture face is damaged.

The poorer-than-expected performance of some fracturing treatments has been an issue for decades. Considerable effort has been devoted to improved modeling of fracturing treatments so that improved expectations can be provided. Fracturing fluids have been modified to enhance cleanup. Proppant conductivity studies have lead to a better understanding of fracture performance. Yet, there are still many treatments, particularly in low-permeability gas wells, that defy efforts to clean up quickly and to produce at the expected rates. This paper revisits the question of whether fracture face damage is an issue in the subsequent performance of a gas well. It will be demonstrated that the landmark paper by Holditch[1] has been misquoted for 25 years. A numerical simulator has recently been written that has reproduced the earlier work, but also expands on it by demonstrating the physical mechanisms by which fracture face damage can reduce gas production and accelerate water production. The simulator includes relative permeability curves for both gas and water, and capillary pressure functions. The role of Laplace pressure, or capillary pressure, will be highlighted in the explanation of how fracture face damage can cause significant loss in well productivity. In addition, the role of relative permeability to gas will be highlighted as to how it ultimately leads to decreased gas production and increased water production when the fracture face is damaged. Introduction The issue of whether fracturing fluids damage the productivity of propped fractured wells is easily 50 years old.[2] Yet, even today our industry is concerned with the causes and remedies for the slow cleanup of fracturing treatments in low-permeability gas wells. Numerical modeling has been a mainstay of the efforts to understand the processes that occur in the formation during and after a fracturing treatment.[3–6] The landmark paper by Holditch in 1979 that numerically explored the effects of formation damage in the matrix extending from the fracture face seemed to settle the issue for most. For most readers, the paper seemed to say that fracture face damage was not an issue, and that formation damage could extend 6 inches from the fracture face with a 99.9% permeability loss before any effect on productivity would be noticed. However, quoting directly from that paper: "... it is obvious that the combined effects of damage, relative gas permeability reduction, and an increase in capillary pressure in the damaged zone can cause severe reduction in gas productivity." Holditch subsequently reiterated this point in various fashion over the next several years as he continued to explore the causes of poor performance with field data and numerical studies.[7,8] Yet, somehow the notion persisted that fracture face damage did not matter. The fact is that the original work essentially consisted of three numerical experiments. The first experiment included gas production with a damaged zone using a single-phase simulator. This was a set of control experiments, or control calculations. These calculations should not be confused with a gas well with 10% water saturation that produces no water. In this first case of a single phase, it is numerically true, and we have verified it with the model presented here, that the permeability in the damaged zone would need to be reduced by at least 99.9% before a loss in gas production could be observed. The second experiment was to explore gas productivity with a two-phase simulator, but without any damage. Once again, this was a set of control calculations. The numerical experiment explored whether gas production could be restored once fracturing fluid invaded the matrix next to the fracture face. The two primary issues were:whether production drawdown can overcome capillary pressure and the discontinuity at the fracture face, andwhether the fracturing fluid can be imbibed deeper into the matrix. Either one of these processes would be sufficient to restore the relative permeability to gas, and thereby allow gas production. These calculations are relevant to gas wells that have been fractured but not damaged. In this second case, it was reported that as long as either (1) the water was mobile and could be imbibed, or (2) production drawdown could overcome capillary pressure, then water invasion into the fracture face would not affect gas production.

Water-based polymers, guar, and derivatized guar have been the mainstay of fracturing fluids for many years because of their low cost and highly controllable fluid rheology. However, these materials can cause significant fracture conductivity impairment leading to poorer than expected well productivity after fracture stimulation. Considerable effort has been applied to reduce the damage caused by these fluids, including:applying special purification chemical processes,improving polymer breakers,formulating fluids with less polymer, andimproving fluid recovery during well flowback after treatment.Each of these processes has incrementally improved conductivity; however, one-half or more of the native conductivity is lost to frac fluid damage derived from the use of guar-based polymers. Recent application of no polymer, surfactant-based viscoelastic frac fluid technology has demonstrated the value of non conductivity damaging fluids by generating high well productivity with small fracture stimulation treatments. While these fluids are generally nondamaging, they are limited in applicability because of high fluid loss and their inability to generate extended fractures at a reasonable cost. This paper presents the laboratory development and initial field testing of a new, viscoelastic fluid technology that produces highly productive fractures with low conductivity damage while providing excellent fluid-loss control and high proppant-transport properties to generate design fracture geometry. This fluid has little sensitivity to temperature and salinity, and rheology is easily controlled. The fluid system combines the best properties of polymer-based fluid technology with those of surfactant-based technology. Fracture Fluid History Hydraulic fracturing as a well-stimulation method began in 1948, with crude oil as the fracturing fluid. Fracturing evolved rapidly and the use of surfactant-gelled hydrocarbons became common. In an effort to reduce loss of the fracturing fluid to the formation and generate larger dimension fractures, surfactantstabilized water/oil emulsion fluids were developed. The use of water-soluble polymers used to thicken these fluids began in the late 1950s. Polymer-thickened, water-based fluids were first used in the early 1960s, and by the late 1960s, guar gum had become the polymer of choice because of its lower cost and viscoelastic behavior. The early 1970's saw significant growth in guar-based fracturing fluid technology. Controlled crosslinking reactions were evoked to provide the rheological properties required to provide low fluid loss to the formation and adequate elasticity to transport proppant into the fracture for these extensive fractures. While these fluids were robust and large fractures could be achieved, the economic performance did not justify the cost. It became generally recognized that crosslinked guar polymer also caused a dramatic loss in fracture conductivity. Laboratory measurements indicated that often less than 10% of the native fracture conductivity was achieved. Most of the remaining fracturing-fluid history centers on reducing the conductivity damage that guar-based polymers cause. Derivatized guar-based polymers were developed to provide cleaner fluids that have more control in crosslinking reactions. The amount of polymer required to accomplish fracture stimulation was reduced. Foaming these fluids with nitrogen or carbon dioxide reduced the amount of polymer being used while providing the fluid rheology required for handling proppant. Computer-controlled blending equipment made it possible to make ultra-low polymer gels that provided "just enough" rheology. Despite these innovations, the typical fracture conductivity achieved was typically less than 30% of the expected conductivity with these fluids. Significant improvements in gel breaking and polymer degradation technology have recently emerged.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractRecovery of fracturing fluid is considered a critical aspect for achieving production performance that meets the expectations of fracture treatment designs. Fluid recovery is often described simply as a percentage of load recovery on a volume basis, without consideration of the composition of the recovered water. Some of this water may in fact be formation water and not original load water at all. Analysis of the ionic composition of the water can determine whether the recovered water is formation water or treatment water. This paper describes a new model that embodies the physics of flow during back-production of a fracturing treatment and incorporates a chemistry "layer" that allows for matching fracturing fluid flowback compositions. The model accommodates formation water having a separate composition from the fracturing fluid. The movements of sodium, potassium, chloride, sulfate, carbohydrate, boron, etc. are modeled during shut-in and production. The compositions of the produced water calculated by the simulator were compared to field production samples.The process of matching the produced water analyses after the fracturing treatment first required a good match of the produced water rates as a function of both time and the produced gas rates. Reservoir and fracture properties were optimized to match the water production. The ionic composition of the flowback water was then matched by adjusting various parameters that might affect how the water was recovered from the reservoir. The information obtained by adjusting these parameters includes relative permeability curves, capillary pressure curves, and some fracture structure details. Deviations of the model from the observed return profiles indicated areas where the understanding of fluid chemistry and physics of flow might be improved.

This paper presents case histories showing that operators drilling in eastern states have increased oil and gas production by reducing the amount of guar polymer used to stimulate a well. The fluid system used in the 80 to 140 F applications in the region is a 20- to 25-lbm/Mgal guar with a buffered borate crosslinker that provides an instant crosslink. The wells being treated as described are shallow, and rapid complexation is needed to ensure proppant transport through the perforations. Laboratory test results are also presented. Rheology and sand transport for the optimized fluid system are compared to similar properties of conventional borate-crosslinked fluids. In general, fluid properties of the low-guar polymer compare to properties of conventional borate-cross linked fluids containing polymer concentrations 5 to 15 lbm/Mgal greater. Viscosity and fluid-efficiency values of the low-guar system (25 lbm/Mgal) compare to a 35-lbm/Mgal conventional borate-crosslinked fluid. Because reservoir cleanup after fracturing is an important component of production, production increases seen in these wells are mainly attributed to the lower gel loading used. P. 197