Introduction The major reason that CO2 stands out as a fluid displacement agent for enhanced oil recovery is because of the adaptability and relatively low cost of CO2 compared with other chemical flooding agents. CO2 miscible displacement could be achieved for a wide spectrum of reservoir oils through an extraction/vaporization process. Even under immiscible reservoir conditions, incremental oil recovery still can be obtained by simple viscosity reduction and swelling of crude oil. Among other desirable properties of CO2 is its high density. At typical reservoir conditions, CO2 is nearly as heavy as reservoir oil; thus, the problem of overriding common to most gas injecting systems could be minimized greatly.In spite of all the advantages of CO2 process, it inherits the disadvantage of high mobility ratio so that the CO2 has a great tendency to channel through the oil, bypassing much of the oil in the reservoir. To alleviate the difficulties, a technique consisting of alternately injecting small CO2 and water slugs has been applied in field test. The injected water interferes with the flow of CO2 to minimize the chance of premature CO2 breakthrough.Another technique, called "programmed slug," has long been applied in polymer flooding to prevent deleterious effects of viscous fingering. More recently, Claridge has developed a method for designing graded banks for both polymer and miscible flooding. His study indicates that the use of a graded slug often results in improvement of oil recovery and/or economic attractiveness.The purpose of this research project was to provide information on whether or not the change of provide information on whether or not the change of injection sequence of CO2 slugs would affect the recovery of oil from a waterflooded porous medium. The research work involved laboratory displacement tests using various injection schemes at a constant amount of CO2. Experimental Equipment The CO2 flooding experiments were conducted using the Ruska miscibility apparatus. The apparatus consists of a 0.2425-in. (0.616-cm) ID stainless steel tube 59 ft (19.3 m) long. The tube was packed with 80–100 mesh glass beads having a porosity of approximately 35% and a permeability of 13 darcies. The tube was coiled and immersed in a constant temperature bath. The apparatus was equipped with a capillary sight glass operated at the selected experimental pressures and temperatures. This device was positioned downstream of the sand pack to provide visual observations of phase change provide visual observations of phase change throughout the entire experiment. The fluid was injected with a constant-rate metering pump manufactured by Instrumentation Specialties Co. A backpressure regulator was used to maintain the desired pressure in the sandpack system. Experimental Procedure The sandpack first was cleaned with isopropyl alcohol that then was displaced with distilled water followed by Drake No. 10 mineral oil until no water was produced. The oil-saturated sandpack was flooded with 3 PV of distilled water. After the waterflooding, the residual oil saturation was determined by a material-balance calculation.Liquid CO2 was drawn from a CO2 bottle and introduced into a holding coil made of 0.25-in. (0.635-cm) stainless steel tubing. The capacity of the holding coil was known, and the weight of CO2 was determined from the difference in weight before and after the coil was filled with CO2. The coil then was connected to the injection system and a predetermined volume of CO2 was displaced into the predetermined volume of CO2 was displaced into the sandpack at a constant temperature of 100 degrees F (37.8 degrees C). SPEJ P. 278

Stimulation of a naturally-fractured, low permeability, low-pressure 2000-foot horizontal well in a low permeability reservoir and in-situ stress environment requires careful stimulation fluid design to minimize the capillary retention of treatment fluids. Therefore, a systematic approach to stimulation design using N2, C02, and N2-foam was used to select one which is most efficient. Stimulation modeling was used to evaluate fracture geometry with particular concern for the minimum pressure rise above parting pressure required for height growth during frac fluid injection. Up to seven zones along the horizontal wellbore are available for stimulation. Each zone was ranked and pre-frac tested to establish pre-frac permeabilities. A N2 and N2-foam data frac was performed in one zone to establish leakoff characteristics. Subsequently, N2, C02, and N2-foam treatments were performed on a 400-foot zone to evaluate the effectiveness Of C02 versus N2 frac fluids. Both the data frac and subsequent stimulations were evaluated in the two least productive intervals in order to use the preferred fluids in the best zones in the reservoir. The post-treatment decline curves for N2 and C02 indicate a C02-based fluid treatment should be performed in the most productive interval to achieve maximum success. Results of the stimulation conducted are presented along with discussion of improvement ratios and potential utility to other horizontal drilling projects. Background The stimulation aspects of horizontal drilling represent a technical challenge in tight formations where the horizontal placement of a horizontal wellbore may not always provide adequate economic production. Little or no published literature exists on the mechanics of hydraulic fracturing of horizontal wells. Typically, long horizontal wells are completed with preperforated liners to preserve hole integrity. The disadvantage of this type of completion is the associated risk of pulling the liner at a later stage of production history and re-running and cementing a casing string such that selective placement of fracturing of fluids can be accomplished. An alternative approach is zone isolation accomplished by the installation of external casing packers and port collars as an integral part of a casing st ring run along the horizontal section. Such a completion arrangement provided stimulation intervals ready-made perforations injecting fracturing fluids into an open hole fracturing condition behind pipe. This was the method of completion used in this 2000 foot horizontal well to avoid problems of formation damage associated with cementing and to eliminate the need for tubing-conveyed perforating of numerous treatment intervals. The U.S. Department of Energy's Morgantown Energy Technology Center has been investigating the merits of drilling high angle wells for more than 20 years. Two high angle wells were completed in the Devonian Shale at 43 and 520 from vertical. Recent emphasis has been on the use of horizontal wellbores to enhance gas recovery efficiency -in tight formations. Initial study of horizontal drilling in fractured Devonian have in the Appalachian Basin involved selection of a geographic area followed by full-field reservoir simulation and initial well design. Once the cite was selected, computer software was used to examine drill string loads, design bottomhole assemblies, track well trajectory, and to provide daily reporting during drilling. P. 451

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract One- and two-dimensional gas reservoir simulators were combined in such a manner that pressure distributions, both in an induced pressure distributions, both in an induced vertical fracture and in the surrounding formation, could be determined as a function of time for any specified well production rate. Basic assumptions regarding the fracture were as follows:the fracture completely penetrates the formation,all flow into the wellbore enters via the fracture, andflow in the fracture is described by Darcy's law. The technique used consisted basically of the alternate use of one- and two-dimensional algorithms for obtaining new pressure distributions in the fracture and the reservoir, respectively. The finite-difference grid penetrates the fracture in the direction normal penetrates the fracture in the direction normal to the fracture axis so that corresponding to each fracture node, there is an adjacent reservoir node. The pressures at these adjacent nodes were used to calculate flow rates from the formation into the fracture, which provided source terms for both algorithms. By alternately using large and small timesteps, stabilized distributions were obtained after a few days production for several different fracture permeabilities. All other reservoir and fracture parameters were fixed so that the effect of fracture permeability on fracture pressure drop and well pressure decline could pressure drop and well pressure decline could be determined. Results are presented for a production rate of 1 MMscf/day from a 40-acre production rate of 1 MMscf/day from a 40-acre square of 2 md-ft flow capacity. The combination model developed provides the only known means of simulating a vertical fracture of given characteristics in a gas reservoir under transient conditions. Thus, the technique developed would be useful in locating wells in a storage field in that the effects of both fracture length and conductivity could be considered prior to drilling and fracturing operations. Introduction The American Gas Association Pipeline Research Committee and the U.S. Bureau of Mines are involved in a cooperative study of methods for increasing the capacity and operating efficiency of gas-storage reservoirs. The expansion of an existing storage field to achieve increased capacity frequently requires that new wells be drilled and fractured. The question thus arises: With regard to the area's preferred direction of fracture and the preferred direction of fracture and the existing formation permeability, what is the minimum number and location of new, fractured wells required to achieve the desired increase in capacity?

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract Water was injected at constant pressure into a single well in a pressure into a single well in a fractured reservoir for a period of 32 days followed by a 9 day shut-in period. Intake volumes of the injection well and pressure responses in 19 surrounding pressure responses in 19 surrounding wells were recorded during the entire test. Type curves were generated by numerical and semi-analytical techniques to facilitate reservoir characterization from the constant-pressure, declining-rate injection data. A single-phase, three-dimensional, semi-compressible simulator was developed and used to match the field-results. The fracture orientation trend of the reservoir was determined, and reservoir permeability and effective fracture length were calculated for the injection well. Type-curves are presented for use in evaluating the presented for use in evaluating the constant terminal pressure case for fractured wells. Introduction Hydraulic fracturing is used extensively to improve the economics of primary oil production and is being used increasingly in waterflood projects involving wells with severe skin damage, lower permeability reservoirs, and reservoirs with wells that were fractured for improved primary production. Previous fears that induced production. Previous fears that induced fractures may result in floodwater "channeling" to production wells are gradually dissipating as more is learned about the nature of these fractures. There is strong evidence to suggest that the vast majority of induced fractures are vertical and extend laterally in a preferred direction. Proper alignment of fractured wells for Proper alignment of fractured wells for pattern flooding can result in pattern flooding can result in displacement efficiency equal to or better than that of patterns using unfractured wells. Donohue, Hansford, and Burton investigated the effect of fracture orientation on displacement efficiency in pattern floods showing the importance of pattern alignment with respect to fracture direction.

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