TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe performance of stand alone screens can be predicted by developing master curves for individual screens based on the screen opening pore size and an effective formation particle size factor. Screen mesh designs and pore structures have unique performance curves which can be used with particle size analysis from whole or sidewall cores to aid in the selection of screens which will meet performance criteria for solids production and flow capacity for a specific wellbore. The paper describes the procedures for developing the performance master curves for screen laminates . Examples are given illustrating the predictive data for solids production and flow capacity for a series of well core samples.

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Summary Understanding the causes of damage to fracture conductivity is vital to design fracture treatments for maximum economic value and to analyze the actual well performance. High-viscosity fluids, resulting from retention of polymer within the proppant pack during closure, play a major role in proppant-pack damage. Viscous fluids are not effectively displaced during flowback and production of hydrocarbon unless the viscosities of the phases are similar. The consequences of viscous fingering in the fracture are discussed, and a method is presented for predicting the retained permeability of proppant packs in which guar-based hydraulic fracturing fluids have been broken. Data required for the method are temperature, polymer molecular weight and final polymer concentration. Introduction Proppant pack damage caused by polymeric fracturing fluids has generally been attributed to residue or high polymer concentrations remaining in the fracture after closure. For example, Cooke found that fluids which yielded lower volumetric levels of residue on breaking generally caused less pack damage. Hawkins and Brannon and Pulsinelli placed greater emphasis on the difficulty of removing high polymer concentrations from the proppant pack. High polymer concentrations are the result of the filtration process which occurs during fracture closure. If the formation pore sizes are too small to allow invasion by guar molecules, the guar concentration in the fracture may increase dramatically. According to the calculations of Brannon and Pulsinelli, a concentration factor of 10 is easily achieved for an average proppant concentration of 3 ppga. They reported that high breaker concentrations are necessary to effectively remove damage. Parker and McDaniel had similar concerns about high polymer concentrations, but they were particularly worried about removing the filtercake. This paper discusses the damage to fracture conductivity resulting from channeling or viscous fingering. Fingering will occur during flowback following a fracturing treatment when low-viscosity fluIds (leakoff or formatIon fluid) pass through the degraded fracturing fluid remaining in the proppant pack. Fingering leads to bypassing of part of the pack, which causes a loss of effective fracture area. The extent of fingering can be predicted from the contrast between the viscosity of the fluid in the pack and the viscosity of the displacement fluid.

To maximize well productivity, it is essential to maximize fracture cleanup. A field study in the Codell formation of Colorado was conducted to examine the effects of guar removal from hydraulic fractures on gas production.The conventional method of quantifying cleanup from a hydraulic fracture has been to report load water recovery; however, this value is affected by any formation water that might be produced. A more quantifiable approach to describing fracture cleanup has been performed in this study by determining the amount of guar returned from the fracture during flowback. A 12-well study was performed by sampling flowback fluids during cleanup. The concentration of guar in each sample was determined using a colorimetric technique allowing the total amount of polymer recovered over the flowback period to be calculated.Under equivalent reservoir conditions (pressure, permeability, etc.) and fracture conditions (width, proppant loading and distribution, etc.), physically, it is reasonable to expect higher production rates from wells which have produced back more guar since a larger volume (porosity) will be available for flow. Under low permeability reservoir conditions such as those in the Codell (-0.01 md), this guar removal will need to provide added length to show an increase in production. This concept is illustrated with field data. For example, wells whose fractures produced 600-700 lb of guar (-180,000 lb proppant) produced gas at rates of 35-40 MSCF/0 whereas wells whose fractures produced 1100-1200 lb of guar produced gas at rates of 70-80 MSCF/0, most likely indicating a cleanup over a longer length of the fracture.In addition, the effects of flowback rate on load water recovery, guar concentration, and guar recovered are illustrated.

Production from high temperature gas wells is strongly related to effective fracture length. Previous literature has described the importance of degrading gelling agents to very low molecular weights in order to minimize mobility ratio differences between the fracturing fluid and gas during cleanup, so that viscous fingering and channeling do not leave large unproductive areas in the propped fractures. However, degraded guar-based fluids at high temperature tend to form insoluble fragments as the backbone is reduced to low molecular weights. The problem in maximizing cleanup and effective frac length is then one of degrading the guar sufficiently so that viscous fingering is minimized while preventing the formation of insoluble material. Recent analysis of flowback from gas wells indicates that channeling is indeed a problem. This paper presents laboratory data of degraded fracturing fluids at temperatures above 180 F using laboratory fracture conductivity results and residual polymer analysis. Field data is presented which indicate current trends in polymer cleanup at these temperatures. Introduction The success of a fracturing operation ultimately depends on the cumulative production increase resulting from the treatment. The chemistry of the fracturing fluid which is utilized in high temperature gas wells and the physical processes during the multiphase flow cleanup determine the fracture area from which production will occur. To provide the industry better fracture stimulation at lower cost, an improved understanding of guar/breaker interactions and the flow processes which occur at high temperatures is needed. Recent work by Pope et al and Penny and Jin have given insight into the impact of gel concentration, multiphase flow and viscous fingering on cleanup of fracturing fluids in gas wells. In a field flowback study by Pope et al, a relationship was suggested between gas production and fracturing fluid polymer returned from the well. Concurrent with this field study, laboratory work was being completed which defined the relationship between polymer mass remaining in the proppant pack and loss of pack porosity. This paper will illustrate these results. Damage Mechanisms Permeability reduction in a proppant pack is the result of a reduction of pack porosity. Factors such as viscous fingering, fines generated by proppant crushing and polymer residue from fracturing fluids can physically occupy pore spaces in the proppant pack, thus reducing its porosity and permeability. The effect of viscous fingering on fracture conductivity damage was discussed in reference 1 for the temperature range of 125-175 F. Other factors in addition to purely viscous effects become important in conductivity damage at higher temperatures. For example, the intrinsic viscosity of a guar molecule has been found to decrease with increasing temperature indicating the polymer is becoming less soluble. This hydrophobic property of the polymer will tend to make the molecules conglomerate together, especially after they are broken down into fragments by chemical breakers or hydrolysis by temperature. This aggregation may increase their ability to block pore spaces in the proppant pack or more importantly, pore throat spaces. Blocking a pore throat will essentially remove the corresponding pore volume from availability for flow. Therefore, the resulting aggregates may block an effective volume to flow that is much larger than the volume which they physically occupy. In order to maximize retained permeability, it is necessary to either prevent the aggregates from forming or mobilize them once they have formed. P. 849