TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractProppant selection in hydraulic fracturing is a critical economic and technical decision that affects stimulation and field development economics. In many cases the selection is based on laboratory data from standardized API conductivity tests on clean packs at specified stress and temperature. These tests predict conductivities that are optimistic compared to observed field performance. Often a laboratory measured conductivity difference of only 5-10% is considered a significant variance when applied to the producing life of a well. The significance of these small differences, however, is often overwhelmed by other factors affecting fracture performance in the field.The selection of a particular proppant should be based on an identifiable difference in performance under field conditions. This requires an accurate assessment of all the damage mechanisms that can and do occur during fracturing and their impact on final conductivity. This paper outlines the primary damage mechanisms and their effect on conductivity, fracture cleanup and ultimate stimulation response. The expected variance in laboratory measurements of conductivity is also quantified.
Summary Critical velocity calculations in the form of charts or simple equations are frequently used by field personnel to evaluate a gas well's flowing conditions to determine if the well is experiencing liquid-loading problems. Literature detailing the critical velocity necessary to keep a gas well unloaded suggests using the conditions at the top of the well as an evaluation point. This is convenient for personnel conducting the evaluation because wellhead pressure and temperature data are readily available. A number of situations exist where the use of the wellhead as the evaluation point can lead to erroneous conclusions. The most obvious situation occurs with a change in geometry downhole when a tapered tubing string is run in a well or when the tubing is set above the perforations. In these instances a more robust evaluation results from using conditions at the bottom of the well and the downhole tubing geometry. Other conditions exist where the use of downhole conditions provides a better evaluation point. The assumptions used in the development of the standard, simplified form of the critical velocity equations and charts may not be appropriate for downhole application. In these cases, the fundamental equations must be used. The calculation of critical velocity requires knowledge of pressure, temperature, produced fluids, and pressure/volume/temperature (PVT) properties. The determination of critical rate requires the same properties with the addition of pipe diameter. The required PVT properties, including surface tension and density for both the gas and liquid phases, are reviewed. Correlations to calculate water-gas surface tension were found to have excessive error, so a new, more accurate method is presented. This paper provides recommendations for the use of a surface or a downhole evaluation point is more appropriate for the determination of the minimum critical gas velocity in a well.
It is commonly observed that hydraulically fractured wells perform as though the "effective" fracture half-length is much lower than the designed half-length. This observation has been explained by various models, including poor fracture-height containment, poor proppant transport, proppant falling out of zone (convection), ineffective proppant-pack cleanup, capillary-phase trapping, multiphase flow, gravitational-phase segregation, and non-Darcy flow, with combinations of any of these mechanisms. With recent improvements in diagnostic measurements of fracture geometry, some of these explanations have lost credibility, but the problem of low effective fracture length persists.This paper presents detailed evaluations of hydraulically fractured well behavior with continuous production analysis, pressuretransient (buildup) analysis, and fracture-treatment evaluation by use of actual field data from a tight-gas reservoir in the Rocky Mountain Region. The various analyses explain the observed producing behavior of the well and lead to a consistent determination of the actual effective fracture half-length compared with the physically created or propped length. Problems relating to semantics and inconsistent fracture and reservoir description, especially the physical processes encompassed by various analytical techniques, will be addressed.Methods will be outlined for predicting the useful effective length from available proppant-conductivity data. The process outlined helps to close the gap between designed-fracture and producing lengths and points out the causes for the remaining system bottlenecks that limit post-fracture well productivity. Finally, the understanding of these mechanisms provides a means to arrive at an economical optimum fracture-treatment design for a reservoir once key parameters are known.
The production of natural gas from shales traces back to the first well drilled in New York in 1821. Over the past 25 years, access to this resource has grown. Recent advancements in drilling and completion technology has enhanced well production rates and production from shales has increased to where it currently supplies 20% of the gas produced by all gas wells in the United States. Well performance data from these shale plays has been compiled and analyzed to develop insight into these tight reservoirs. These results are compared and contrasted to determine similarities and differences among the plays. Comparisons with classical gas reservoirs and tight gas reservoirs are made to provide additional insight.
Gas wells producing late in their life are normally subject to liquid loading problems. As rates fall below the critical rate necessary for unloading, a static liquid column will often develop in the well. This can result from condensed water out of the gas phase or formation water being produced into a well having insufficient gas velocity to clear the liquid from the wellbore. The presence of this liquid column impairs the well performance by imparting additional back pressure on the reservoir. The water saturation around the wellbore can increase causing a reduction in the near well effective gas permeability which further compounds the problem of keeping the well unloaded. Traditional methods of evaluating well performance do not properly capture this phenomena; therefore, the existence of additional back pressure on the reservoir can go undetected. Wells continue to produce, but at a reduced rate because of the liquid column. Numerous analysis techniques are available to model static liquid columns in wellbores. A review of these methods and an evaluation of these techniques is presented. Comparisons with field data are made to ascertain the accuracy of the methods and to select an appropriate method to model well performance. Incorporation of this method into a well design allows for the optimization of well productivity. Introduction Static liquid columns will form if the well is producing at an insufficient gas velocity to clear the free liquid from the well. The presence of a static liquid column impairs the well performance in the following two ways. First, the column places additional back pressure on the formation as the well is produced and second, standing water across from the sand face is spontaneously imbibed into the formation reducing the near well effective gas permeability. Recognizing the existence of the static liquid column is the first step in improving future well performance. Accurately estimating the flowing bottom hole pressure in the presence of a static liquid column is a critical part of properly characterizing the actual flow capacity of the well. This paper will discuss several methods previously presented in the literature comparing the calculated bottom hole pressure from each to field examples. Two conditions are required to form a static liquid column in a flowing gas well. The first requirement is the presence of free water. Free water in the completion can be a result of water condensation from the gas phase or formation water. The presence of condensed water can be determined in Fig 11 or analytically from a simple method published by GPA2. Fig. 2 shows a depiction of the equilibrium water content of the gas stream over the length of the wellbore. Gas saturated with water enters the wellbore from the reservoir. As pressure and temperature changes along the well, the equilibrium water content of the gas decreases allowing water to condense. In this instance, free water can be expected to condense out of the gas above 9,000 ft. The second requirement to form a static liquid column is that gas velocity in the wellbore is below the critical velocity to continuously lift the free water in the completion to the surface. If the well's production string consists of multiple tubing/casing diameters actual velocity in each string must be considered in the analysis. Furthermore, upsets in production can aid in the accumulation of free water at the bottom of a well even though the production rate is above the critical rate at the surface. Critical Unloading Velocity A method for calculating the minimum flow rate for continuous liquid removal from a gas well was proposed by Turner et al.3 in 1969. The method is based upon a model of liquid droplets entrained in a high velocity gas stream. The minimum velocity required to keep the liquid moving up the well is derived from the terminal fall velocity of the largest droplet which can exist. Droplet size is controlled in part by interfacial tension. Turner devised an equation to calculate the terminal fall velocity of the largest droplet. After testing this equation on over 480 wells, Turner suggested an upward adjustment of 20 percent resulting in the following equation.
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