Hydraulic fracturing has been the stimulation/completion method of choice to enhance production for the vast majority of natural gas reservoirs throughout the world. However, the post-treatment behavior of hydraulically fractured gas and gas-condensate reservoirs is complex. This work addresses important aspects of this behavior. Many natural gas reservoirs exist in the region of retrograde condensation. During production of hydraulically fractured wells, the pressure gradient formed between the reservoir pressure and the flowing bottomhole pressure is likely to result in liquid condensation normal to the fracture face and extending at considerable distance into the reservoir. This leads to an unavoidable reduction of the relative permeability-to-gas, a phenomenon, which was correlated, based on preliminary experimental results that has been obtained. Such a relative permeability reduction depends on the phase behavior of the fluid and the penetration of the liquid condensate into the reservoir. The latter depends on the pressure drawdown imposed on the well. This situation causes a well performance impairment, which behaves as if an apparent damage, tantamount to fracture face damage has affected the fractured wells. Well testing of such wells invariably calculates much shorter apparent lengths than actually placed. This work proposes a model that predicts the performance of hydraulically fractured gas condensate reservoirs (quantifying the effects of gas permeability reduction), adjusts fracture treatment design, calculates the optimum fracture morphology and presents guidelines for the calculation of the optimum pressure drawdown during production to maximize well performance. While these issues are important in all gas reservoirs they become particularly crucial in higher-permeability cases. Introduction The pressure and flow rate behavior of a gas condensate is distinctly different from the behavior of a two-phase reservoir. In a two-phase oil and gas reservoir the two-phase envelop describes a region bracketed between the bubble point pressure and the flowing bottomhole pressure. Such behavior of gas condensate reservoirs applies to the left (i.e., at lower temperature) of the pseudo-critical point. Starting at the right of the pseudo-critical point, the locus of the dew point pressures curves until it reaches the cricondentherm point (maximum temperature point). Between the pseudo-critical and the cricondentherm points, as the pressure declines from the dew point pressure (at constant temperature), liquid emerges. The amount of liquid increases as the pressure in the reservoir decreases until a certain value at which further reduction of the pressure causes the liquid to re-vaporize. This region is called the retrograde condensation zone and reservoirs experiencing this phenomenon are known as gas condensate reservoirs. Many natural gas reservoirs behave in this manner. During production from such reservoirs, the pressure gradient formed between the reservoir pressure and the flowing bottomhole pressure is likely to result in liquid condensation near the wellbore. The producing rate of a gas condensate reservoir is not only affected by the pressure gradient but is also a more complex function of the actual value of the flowing bottomhole pressure. The value of the bottomhole pressure controls the amount and distribution of liquid condensate accumulation near the well with an unavoidable relative permeability reduction, which leads to a significant loss in well productivity. A number of published papers have documented productivity loss in both simulation studies and measured field data ((Hinchman and Barree (1985), Ali et al. (1997), Blom and Hagoort (1998), Fussell (1973), Pope et al. (1998) Carlson and Myer (1995), Settari et al. (1996)). Carlson and Myer (1995) investigated the effects of gas condensate dropout on the performance of a fractured well in a lean condensate reservoir. Settari et al. (1996) presented a case study to discuss the productivity of fractured gas condensate wells.

Oil and gas production from unconventional reservoirs has witnessed significant growth in the last few years. Historically, massive stimulation treatments have been used to produce these hydrocarbons. While the in-place hydrocarbon volumes are often large, the challenge is to increase recovery while using fewer resources. One of the technologies that have been used to address this challenge is the channel fracturing technique. A number of horizontal wells have been stimulated in the Hawkville field of the Eagle Ford shale with this technique. The objective of this work was to evaluate the impact of the channel fracturing technique in these wells by using numerical reservoir simulation. Numerical simulations were performed on a total of 15 horizontal wells. Six wells were completed with channel fracturing and nine wells were completed with slickwater or hybrid fracturing treatments. Because the Hawkville field has large variations in fluid composition, wells producing in the condensate-rich section were studied separately from those in the dry gas section. A consistent history matching methodology and workflow was applied across all wells which enabled a direct comparison of results. Results from analytical work, such as normalized production comparisons, were used to narrow down the range of uncertainties and assumptions made in the numerical simulations. A trend emerged from the analytical evaluations, showing that wells completed with the channel fracturing technique have higher productivity while using significantly less proppant and fracturing fluid. Numerical simulations confirmed the finding and provided insights on the cause of higher production on these wells. Unlike analytical methods, numerical simulation can model changes in complex fracture properties between wells, the effects of transient flow, shale gas desorption from kerogen, interference effects between perforation clusters, and accounts for differences in shale reservoir quality between wells. Furthermore, calibrated well models allowed for sensitivity studies such as evaluating the impact of changes in fracture geometry and conductivity on future wells. Reservoir modeling provided an estimation of effective stimulated fracture volume and fracture conductivity. Wells treated with the channel fracturing technique were observed to have on average 50% greater effective stimulated volume and more than double the stimulated conductivity compared to wells fractured with slickwater. When compared to wells fractured with hybrid treatments, channel fracturing wells had on average 27% greater effective stimulated volume and 50% more stimulated conductivity.

The hydraulic channel fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, which provides for highly conductive paths for the flow of fluids from the reservoir to the wellbore. These channels are created through a process that combines fit-for-purpose geo-mechanical modeling, surface equipment controls and fluid and fiber technologies. This paper reports the first implementation of the channel fracturing technique in horizontal wellbores. A section of the Eagle Ford formation (TVD 10,900 - 11,500 ft) in the Hawkville field near Cotulla, Texas was selected for this study. This section comprises mainly limestone with 100 to 600 nD permeability and 7 to 10 % total porosity. The formation requires horizontal laterals with multi-stage hydraulic fracturing for economic production. The channel fracturing technique was evaluated in twelve horizontal wells. Results from thirty eight offset wells treated with conventional techniques (slickwater or hybrid-type treatments) are also reported to compare performance. Non-normalized data from this sample of fifty wells showed hydrocarbon production increases ranging between 32% and 68% in favor of the channel fracturing technique. The Hawkville field comprises a gas-rich section and a condensate-rich section. Reservoir simulations were performed on a sample of four wells located in the gas-rich section and two wells located in the condensate-rich section of the field to generate sets of normalized production data. These simulations accounted for variations in completion strategy, bottom hole flowing pressures and reservoir quality. Normalized production data for the sample of wells located in the gas-rich section of the field showed that the channel fracturing technique increased gas production by 51%. Normalized production data for the sample of wells located in the condensate-rich section of the field indicates increase in condensate production by 46%. Results from these history matches are consistent with the hypothesis that the channel fracturing technique enabled higher production by two concomitant mechanisms: increased area of contact with the reservoir and enhanced connectivity between the reservoir and the wellbore through highly conductive channels. Positive features that were also observed during this campaign such as the elimination of near-wellbore screen-outs and significant reductions in proppant and water consumption are also summarized and discussed.

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fax 01-972-952-9435. AbstractIn this case study we address the problems associated with fracturing tight gas sands when nearby water sands are present. Often times the problem is that the created fracture might intersect the water sands which can impede the gas production and in extreme cases can kill the well. Production forecasts based on calibrated permeability values can be performed to show the impact of water production to gas production. If the production forecast indicates that there is enough gas to unload and carry the water to surface then an optimized larger fracture treatment based on effective and relative permeabilities can be performed across both gas and water intervals. If there is not enough gas present to unload the water then the fracture treatment must be carefully designed such that the fracture length is still optimized and water penetration does not occur.Around the world, strands of tight natural gas resource lie unproduced next to and within water bearing sands. The production optimization process that is described combines several completion techniques that incorporate currently available technology to give the completion engineer one more tool to gain access to these reserves. This technique is not geographically limited and applies to any tight gas sand resource.