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Continuous increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from existing wells. In most gas wells, water and/or condensate is produced along with gas. In mature gas wells, decreasing formation pressures and gas velocities gradually cause the wells to become "loaded" with liquids. A method commonly used to deliquify these wells is through the application of chemical "foamers". However, these traditional foamers tend to be ineffective as the condensate-to-water ratio increases. This paper describes the performance of a novel foamer specifically designed to unload condensate from wells. This foamer helped unload a gas well that produced condensate via intermittent production at 2:1 condensate-to-water ratio. Parameters for well selection are described, as well as operational processes to maximize continous production. As a result of this treatment, the daily average gas production rate increased significantly and shifted the daily on:off production cycle from 1:1 to 11:1. This minimized well down time and increased the overall daily production averages by 60 percent. Introduction Gas producers traditionally have observed that increasing amounts of liquid hydrocarbon (condensate) significantly affect the ability of conventional foamers to deliquify liquid loaded gas wells. This situation is prevalent in several wells in South Texas. This work describes the results from a trial using a foamer specifically designed for condensates. Because of the difficulties in treating liquid-loaded wells with higher condensate cuts, the operator at this location uses a variety of methods to prevent liquid loading in marginal gas wells. These methods include: the use of intermitters; velocity strings; adding additional compressor capacity; and applying chemical foamers. The newly-developed condensate foamer was designed to provide a more cost-effective way to unload condensate-loaded gas wells. Intermitters allow for periodic gas flow interruptions that enable the formation to temporarily increase down-hole gas pressure in the reservoir during the shut-in phase. This accumulated pressure provides sufficient gas velocity to unload liquids from the well when opened. This continues until the actual gas velocities decrease below the critical velocities where loading occurs. The disadvantage of this type of production method is the loss of gas (and condensate) production during the "off" periods. Velocity strings are inserted tubing strings that are narrower than the existing tubing (typically a wide capillary string) that enable the user to physically increase the linear velocity of the gas and, in turn, prevent liquid loading. The disadvantage of this type of production method is the possible loss of production, due to the restriction the string creates. Added compression capacity reduces the overall wellhead pressure and thus increases the differential pressure with the down-hole pressure. This removes gas back-pressure restrictions that are conducive to liquid loading. The disadvantage of this option is the large capital expenditure required to add compressors. For this trial, the condensate foamer was applied to a well where an intermitter was being used to prevent liquid loading. This paper discusses the well selection criteria used to identify candidate wells, in addition to presenting the performance results of the condensate foamer applied to this well.

Surfactant dewatering of gas wells is a method best used in an operating envelope determined by existing gas flow rates, well bore inner diameters, pressures and temperatures. Baker Petrolite has designed a computer model to determine this operating envelope. The methodology can help delay costly mechanical dewatering methods yet still maintain production in the field. Case studies for both production and gas storage wells will be discussed. Introduction Since 1993 the total annual natural gas consumption in the United States has been greater than 20 Tcf.1 Natural gas production and reserves in the United States have been maintained by a large drilling program. The number of gas well completions added each year in the United States has increased from 13,000 –14,000 prior to the year 2000 to 22,800 in 2001.1 It has been estimated that close to 25 percent of the well head capacity comes from wells less than a year old.1 Decline rates in new Texas gas wells that compromise one third of the natural gas production have changed from 20 % in the first year for wells drilled in the 1970's and 1980's to more than 55% for wells drilled in 1998 and 1999.2 Surplus capacity is little more than 10 % of the average consumption. Stored natural gas is necessary to supply peak winter demand of natural gas. The proper sizing of a gas well becomes difficult in the context of steep gas production declines. Wellbore flow performance at high gas velocities improves with larger diameters. At low gas velocities, gas is unable to transport liquid out of the well bore. When liquid accumulates in the well bore, the liquid hydrostatic head can kill the well. Turner, Hubbard, Duckler determined the minimum gas velocity needed to transport liquid in a gas well based upon particle and drop break up mechanics.3 Coleman, Clay, McCurdy, and Norris slightly modified the criteria of Turner to describe field test data.4 In the work of Turner, a constant drag coefficient of 0.44 was used. Nosseir, Darwich, Sayyough and El Sallay found that incorporating the Reynold's number dependence of the drag coefficient provided a better fit of field data without using an empirical constant.5 Li, Li and Sun modified the Turner equation for liquid droplets with a flat shape.6 Underground gas storage facilities enable the reliable delivery of gas to the customer during days of peak demand. Normally, the underground storage wells act as both injection and withdrawal wells. Injection and withdrawal periods into the storage unit are spaced. Wells may need to be killed for maintance and to prevent leakage of gas from the storage facility. Surfactant dewatering of gas wells is one method of extending the life of a gas well. Surfactant dewatering of a gas well uses the existing flow of gas to remove liquid from the well. The surfactant aids the removal of liquids by lightening the density of the liquid droplet, and by allowing the creation of smaller droplets. The integration of the effects of surfactant on liquid quality and dynamic surface tension with the liquid loading equation have been initially described in work on corrosion inhibitor foamer combinations.7,8 Case studies where surfactant dewatering helped increase gas well production and remove liquids from pipelines were described in a subsequent paper.9 In this paper, the effect of surfactants on changing liquid surface tension and increasing foam quality is briefly described. The scientific identification of gas well opportunities using foamers is then shown. The implication in ultimate recovery for a characteristic decline curve will then be calculated. Chemical compatibility of foamers will then be presented. A case study will then be presented for a production wells where foamer helped stabilize and increase production. One case where the current technology was used to increase deliverability of a gas well where the liquid level increased in the well due to depletion of the reservoir is described. In all cases the use of surfactants provided operators with a cost effective means of maintaining or increasing gas production.

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