Gidley, J.L., SPE-AIME, Exxon Co. U.S.A. Mutti, D.H., SPE-AIME, Exxon Co. U.S.A. Nierode, D.E., SPE-AIME, Exxon Production Research CO. Kehn, D.M., SPE-AIME, Exxon Production Research Co. Muecke, T.W., SPE-AIME, Exxon Production Research Co. The performance of several wells completed in tight gas sands that have been stimulated by massive hydraulic fracturing is compared with predicted performance. Results agree when the net sand thickness available in the performance. Results agree when the net sand thickness available in the wellbore of the fractured wells is reduced by a factor of 4. Sand discontinuity is used to explain this result. Introduction Even though gas has been produced in limited quantities from tight gas sands in the Rocky Mountain area for the last several decades. development of this area as a significant source of gas production has occurred only since the early 1970's. Efforts intensified with the growing awareness of the domestic energy shortage. The Federal Power Commission estimates that about 600 Tcf gas reserves can be found in this area. A National Gas Survey indicates that these reserves can be exploited. Interest in the area has revived. Recent increases in federally regulated interstate natural gas prices have provided an economic incentive for developing these provided an economic incentive for developing these reserves. Both nuclear stimulation and massive hydraulic fracturing (MHF) have been suggested as methods for producing this latent gas. Fig. 1 shows the geographical producing this latent gas. Fig. 1 shows the geographical locations of several tests of both methods and also identifies the principal geologic basins of interest. This paper does not deal with the results of nuclear stimulation experiments because these results are covered elsewhere. Applications for that technology are now dormant. Rather, we examine the results of several MHF treatments in the area to see how the production rate from fractured wells compares with predicted performance. The size and calculated geometry of the fracture and known reservoir properties of the sands are used for these comparisons. With a few noteworthy exceptions, the MHF results for the Mesaverde and Fort Union sands (the major gas sands in the Rocky Mountain area) have been largely disappointing. Although the problem originally was attributed to certain deficiencies problem originally was attributed to certain deficiencies in the hydraulic fracturing technique, it now appears that this response is inherent in the nature of the formations. This study was not limited to Exxon Co. U.S.A. wells alone, since our involvement in the Rocky Mountain area has been minimal. We also looked at the performance of other operator's wells. For the latter wells, most data were obtained from trade journals, publications of the federal government (since most of the wells are on federal leases), local newspaper articles, or other sources. Some of these companies have not been contacted directly regarding the data used on their wells or this analysis of well performance. Other companies are mentioned in this paper performance. Other companies are mentioned in this paper for well identification only, and no concurrence on their part is implied with the conclusions drawn. part is implied with the conclusions drawn. Type of Treatments Examined The term massive hydraulic fracturing used here refers simply to very large fracturing treatments, generally an order of magnitude larger than conventional fracturing procedures. Typically, an MHF involves more than procedures. Typically, an MHF involves more than 100,000 gal fracturing fluid and more than 200,000 lb sand. JPT P. 525

A new fracturing process using a high strength bauxite as the proppant has been developed which generates long-lasting, high conductivity fractures in deep, hard, high stress formations. No unusual difficulties have been experienced in handling and pumping the proppant. Good production increases have been obtained in most of the wells treated with the new process. The process is particularly applicable to deep reservoirs. Detailed economic analyses, made with a reservoir simulator and using reservoir and economic parameters for a deep, tight, East Texas area gas well, show that large economic benefits can be expected from use of the process. Introduction The use of high-strength bauxite as the proppant in hydraulic fracturing was reported proppant in hydraulic fracturing was reported at the Fall Meeting of SPE in 1976. The purposes of this paper are to give an updated purposes of this paper are to give an updated report on usage of the material in Exxon USA wells and to discuss an economic analysis that can be used to evaluate the usage of an improved propping material. propping material. Many deep wells will require hydraulic fracturing treatments in order to produce at economic rates. Other wells can be greatly improved economically by a successful hydraulic fracturing treatment. To achieve successful fracturing results, a material having properties superior to sand is needed to prop open the hydraulic fractures created at the high earth stresses present in deep wells. Silica sand, the commonly used propping material, tends to crush in closure stresses encountered in deep formations, producing fine particles or fragments that can drastically reduce fluid conductivity of the propped fracture. This crushing of the sand leads to lower productivity of the well. The problem of finding a proppant material that will withstand high stress without excessive crushing has been the subject of research in the oil industry for a number of years. Exxon Production Research Company (EPR) worked for several years on this problem. A wide variety of materials were tested in the laboratory, following the development of equipment suitable for simulating reservoir conditions.

Two treating systems have been developed to provide corrosion control of gas-lift well tubulars by continuously injecting corrosion inhibitor into the gas-lift gas stream. The amount of inhibitor injected is controlled by either a system of proportional divider valves or by an auto mated time-shared proportional divider valves or by an auto mated time-shared system using an electronic scanner and an adjustable time to control solenoid valves. Introduction Internal corrosion of tubulars in gas-lifted oil wells along the Texas Gulf Coast is widespread and often quite severe. The corrosion attack is caused by production of large volumes of salt water, particularly from the predominantly water drive reservoirs in this area, predominantly water drive reservoirs in this area, coupled with the presence of carbon dioxide in the produced gas. Carbon dioxide dioxide dissolved in salt produced gas. Carbon dioxide dioxide dissolved in salt water forms an acidic brine solution that causes a general corrosion attack on steel tubulars. This form of corrosion often results in heavy localized pitting, with the greatest metal loss in gas-lifted wells usually occurring in the portion of the tubing string above the operating gas-lift portion of the tubing string above the operating gas-lift valve. Corrosion severity is often such that tubing strings require replacement as frequently as every 6 months. Plastic-coated tubing has solved, to an extent some of our severest tubing corrosion problems; but it cannot be economically justified in many instances. During the past several years, corrosion has become an increasing problem as a result of the need for capacity production. Corrosive high-water-cut wells are being production. Corrosive high-water-cut wells are being produced; and additional turbulence in the tubing from produced; and additional turbulence in the tubing from higher producing rates accelerates the corrosion-erosion attack. This paper describes systems developed to replace conventional down-hole corrosion-inhibitor batch treatments with continuous inhibitor injection into the gas-lift stream. The systems allow control of treatment for individual wells. Conventional Corrosion Control Methods Corrosion of steel tubulars in gas-lift wells can be controlled by application of properly selected corrosion inhibitors. Corrosion control programs for gas-lift wells commonly use one of the following batch treating techniques: Tubing displacement Corrosion inhibitor in displaced to the bottom of the tubing string with the inhibitor forming a protective film on the tubing. Weighted inhibitor weighted corrosive inhibitor is pumped into a well where it falls to bottom then slowly comes back in the produced fluid, forming and replenishing a protective film on the tubing. Formation squeeze Inhibitor is squeezed (pumped) into the producing formation; inhibitor is adsorbed on the formation and subsequently desorbs into the produced fluids, forming and replenishing a protective film on the tubing. Successful corrosion control programs using these treating methods are expensive, since they usually require a truck-mounted pump and operator in addition to the inhibitor. Schedules for such programs are frequently difficult to maintain, resulting in treatment inconsistency. It is also difficult to optimize treatment size vs frequency to avoid periods of under-or over-treatment. Operating problems often associated with programs using batch treating techniques are the following (1) Wells must be shut in to treat, resulting in lost production. JPT p. 624

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