This paper discusses how to analyze past performance and predict futureperformance of tight gas wells stimulated by massive hydraulic fracturing (MHF)using finite fracture flow-capacity type curves. The limitations ofconventional pressure transient analysis and other methods of evaluating MHFtreatment are discussed. A set of constant well-rate and wellbore-pressure typecurves is presented. Introduction Because of the deteriorating gas supply situation in the U.S. and theincreasing demand for energy, the current trend is to consider seriously theexploitation and development of low-permeability gas reservoirs. This has beenpossible because of changes in the economic climate and advances in wellstimulation techniques, such as massive hydraulic fracturing (MHF). It nowappears that MHF is a proven technique for developing commercial wells inlow-permeability or "tight" gas formations. As the name implies, MHF isa hydraulic fracturing treatment applied on a massive scale, which may involvethe use of at least 50,000 to 500,000 gal treating fluid and 100,000 to 1million lb proppant. The purpose of MHF is to expose a large surface area ofthe low-permeability formation to flow into the wellbore. A low-permeabilityformation is defined here as one having an in-situ permeability of 0.1 md orless. Methods for evaluating a conventional (small-volume) fracturing treatmentare available, but the evaluation of an MHF treatment has been a challenge forengineers. To evaluate the success of any type of fracture stimulation, prefracturing rates commonly are compared with postfracturing production rates.These comparisons are valid qualitatively if both pre- and postfracturing ratesare measured under similar conditions (that is, equal production time, samechoke sizes, minimal wellbore effects, etc.). Unfortunately, to evaluate thesuccess of different kinds of fracturing treatments, pre- and postfracturingproduction rates often are measured pre- and postfracturing production ratesoften are measured and compared using not only the same well tested underdissimilar conditions, but also the same kind of comparisons between differentwells that may even have different formation permeabilities. Thus, resultsoften are invalid and may cause misleading conclusions. Moreover, suchcomparisons do not help predict long-term performance. To predict long-termperformance for MHF wells, reliable estimates of fracture length, fracture flowcapacity, and formation permeability are needed. Pressure transient methods for analyzing wells with small-volume fracturingtreatments are based on the concept of infinite or high fracture flow capacityand are used to determine the effectiveness of a stimulation by estimating thefracture length. Our experience indicates that these methods are not adequatefor analyzing wells with finite flow-capacity fractures. Such methods provideunrealistically short fracture lengths for MHF wells provide unrealisticallyshort fracture lengths for MHF wells with finite flow-capacity fractures.Furthermore, fracture flow capacities cannot be determined. Includes associated paper SPE 8145, "Type Curves for Evaluation andPerformance Prediction of Low-Permeability Gas Wells Stimulated by MassiveHydraulic Fracturing."

In this 960-acre project, more than a million barrels of oil was displaced from a previously waterflooded reservoir. Producing rates were as high as 550 BOPD and injected air/water ratios were low. Although COFCAW poses many problems, most of them can be handled, and its great advantage is that the injecting media are the cheapest to be found: air and water. Introduction Purpose Purpose Several years ago Amoco Production Co. began field testing a new oil recovery process. This process involves Combinations Of Forward Combustion And Waterflooding. For brevity we call it COFCAW.Pilot COFCAW tests were conducted in several reservoirs of several types. This program of pilot tests is discussed in a separate paper. One of these pilot tests, which is discussed in another separate paper, was conducted in a previously waterflooded portion of the Sloss field, Nebraska. The results of this tertiary recovery pilot were encouraging. It became apparent, however, that the economic potential of COFCAW as a tertiary recovery method could not be determined by a pilot test alone. The pilot therefore was terminated before completion.A full-scale tertiary COFCAW project was undertaken at Sloss. Begun with six 80-acre five-spots and later expanded to 960 acres, this became the largest test of any tertiary recovery method yet reported.The purpose here is to discuss the full-scale COFCAW project at Sloss. Descriptions of the COFCAW process' and the Sloss field are given elsewhere. Discussion The Full-Scale Project Area As shown in Figs. 1 and 2, the expanded or full-scale project at its final maximum size involved about 960 project at its final maximum size involved about 960 acres. Pertinent reservoir data for this area are given in Table 1.Previous engineering studies indicated that better economics could be obtained by operating COFCAW in phases or stages than by operating in the entire reservoir at once. Therefore, the plan was to begin with six 80-acre five-spots. When these had been burned out, the same equipment was to be used for a second similar phase, and so on. Events did not work out exactly that way.As planned, the project began in Feb. 1967 with six 80-acre five-spots called the Phase I area (see Fig. 2). Incidentally, note in Fig. 2 that one of the five-spots was highly asymetrical; this was because offcenter Well 105 was used for injection instead of center Well 18, a COFCAW pilot producer. Note also that the northeast half of the pilot area was arbitrarily included in Phase I, even though Well 13 was never produced during the expanded project.For various reasons, additional wells were added to the project from time to time. Because intermittent testing indicated the presence of combustion gas, two producers in the poorer-quality, lower-productivity producers in the poorer-quality, lower-productivity pay near the northwest edge of the reservoir were pay near the northwest edge of the reservoir were added in March 1968. More important, because the available air-compressor and water-pump capacity could not be fully used in the Phase I injection wells, other wells were added in attempts to use all of the available fluids. JPT P. 676

Air injection in the COFCAW project at Sloss field, Nebraska, was terminated in July 1971, but water injection was continued. The result has been the production of significant volumes of oil. Here is a discussion of field performance, of data obtained from core holes, and of possible modifications for future COFCAW operations. Introduction From Feb. 1967 to July 1971 a 960-acre COFCAW (Combination of Forward Combustion and Waterflooding) project was operated in the Sloss field, Nebraska. project was operated in the Sloss field, Nebraska. Well locations for the COFCAW area are shown in Fig. 1 and pertinent reservoir data are given in Table 1. During approximately 4 1/2 years in which air was injected, 646,776 bbl of stock-tank oil was recovered (not including 80,000 bbl captured during pilot operations). In addition, about 34,000 bbl of hydrocarbons vaporized by Rue gas pasting through the reservoir was vented to the atmosphere. Cumulative injections into the COFCAW area to July 1, 1971, were 13,754 MMscf of air and 10,818,000 bbl of water. The over-all average injected-air/produced-oil ratio was 21,266 scf/bbl. When air injection was terminated in July 1971, water injection was continued with encouraging results. To Jan. 1, 1974, an additional 189,000 bbl of stock-tank oil had been recovered: Adding this to that produced during air injection brings the total recovery to 836,000 bbl of oil and reduces the over-all air/oil ratio to 16,452 scf/bbl. (If all hydrocarbons in the vent gas had been recovered, the over-all air/oil ratio would calculate to be about 11,700 scf/bbl). After air injection was terminated in 1971, it was decided that core holes should be drilled in an effort to determine the following:Residual fuel saturation-i.e., how much hydrocarbon was left in those zones through which the combustion zone had moved.Variation in vertical sweep with distance from the injection well.Areal coverage by the burning front.Maximum temperature distribution - i.e., how the maximum temperature to which the rock had been subjected varied both areally and vertically.The effective permeability of the reservoir rock and whether some material had been deposited in the rock and reduced the flow capacity. Five core holes were drilled in late 1971 and early 1972. The COFCAW process is described in Refs. 1 through 4. Details of a 40-acre pilot test conducted in the Sloss field are given in Ref. 5 and details of the 960-acre project are given in Ref. 6. Our purpose here is to discuss the results of the core hole program and the performance of the COFCAW area under the influence of water injection. Selection of the Core Hole Locations The core holes were drilled in the Well 16-Well 17 quadrant of the five-spot pattern in which Well 16 was the center injector. This particular quadrant was selected because Well 16 was one of the better injection wells and because there was evidence that heat breakthrough had occurred at Well 17. Injection rates as a function of time for Well 16 are shown in Fig. 2. JPT P. 1439

Parrish, David R., SPE-AIME, Parrish, David R., SPE-AIME, Amoco Production Co. Pollock, Charles B., SPE-AIME, Pollock, Charles B., SPE-AIME, Amoco Production Co. Ness, N. L., SPE-AIME, Amoco Production Co. Craig Jr., F. F., * SPE-AIME, Amoco Production Co. The operability of COFCAW in previously waterflooded reservoirs was demonstrated by the production of 80,000 barrels of oil from a 40-acre five-spot. This thermal recovery pilot was unusual in several respects. The pay was thin and deep, the oil was light, and the viscosity was low. Introduction The purpose of this paper is to describe a pilot test of COFCAW in a previously waterflooded portion of the Sloss Field, Nebraska.The Sloss pilot was one of a series of COFCAW field tests conducted in several reservoirs of differing types. This field test program is the subject of a separate paper.The COFCAW pilot at Sloss was not carried to completion but was replaced by a full-scale project. The expanded COFCAW project is the subject of another separate paper.The decision to expand COFCAW operations at Sloss was based partly on the encouraging results of the pilot and largely on an urgent need for a full-scale evaluation of this tertiary oil recovery method. The Sloss Field The Sloss field, with about 38 million bbl of oil originally in place is one of the larger fields in the Denver basin. It is near the city of Kimball, in Kimball County, Nebr.The field was discovered in Nov. 1954. By mid-1958, when primary operations ended, there were 89 wells in the field, most of them on 40-acre spacing. Additional wells completed later brought the total number to slightly more than 100.The field produces a light (38.8 deg. API) paraffinic oil from a stratigraphic trap in well consolidated Muddy "J" sandstone. There are two main reservoirs -- the J1 at a depth of about 6,200 ft and the slightly deeper J2. In some areas, the two reservoirs are separated by only a few feet of shale. Much of our discussion will be confined to the J1 reservoir (Fig. 1), since only that reservoir was involved in the COFCAW operations. Production History Production History Early performance was typical of volumetric reservoirs. Peak production of 9,600 BOPD occurred in mid-1957, about 21/2 years after discovery. By 1958 the reservoir pressure had declined from the original pressure of 1,328 psia to less than 400 psia, well pressure of 1,328 psia to less than 400 psia, well below the bubble-point pressure of 689 psia. About 11 percent of the original oil in place was recovered percent of the original oil in place was recovered during pressure depletion operations.The field was unitized with Amoco Production Co. as operator and a waterflood was started in mid 1958. Response to the waterflood was good, and a maximum incremental oil producing rate of about 3,000 BOPD over the estimated primary rate was obtained. By the start of the COFCAW pilot project in mid-1963, most of the reservoir had been waterflooded. (For a description of the COFCAW process, see Ref. 1 and its references.) JPT P. 667

Performance of a Forward Steam Drive Performance of a Forward Steam Drive Project-Nugget Reservoir, Winkleman Project-Nugget Reservoir, Winkleman Dome Field, Wyoming Despite its lack of some of the characteristics generally considered essential for a successful forward steam drive, this shallow reservoir, with its high saturation of viscous oil, has shown a gratifying response. Introduction The Winkleman Dome field in Fremont County, Wyo., was discovered in 1944 when the first well was completed in the Tensleep reservoir (Fig. 1). Early development in the field was exclusively in the Tensleep and Phosphoria reservoirs although the existence of oil in the shallower Nugget was recognized. Because of a lack of market and the low price of 14deg. API gravity crude, the Nugget could not be developed profitably. This situation was unchanged until crude prices increased by about 40cts/bbl in 1957. Five wells were drilled in 1958 and 1959 to obtain information about the reservoir, crude properties and primary performance. Studies indicated that none of primary performance. Studies indicated that none of the usual secondary recovery methods would be profitable. Even though the reservoir did not possess all profitable. Even though the reservoir did not possess all the criteria considered desirable for a steam injection project, it was believed that forward steam drive project, it was believed that forward steam drive should be tried. A steamflood was started in March, 1964, expanded in 1965, and expanded again in 1967 to the present area. The equipment used in these operations was discussed in an earlier paper. The purpose of this paper is to present performance of the Nugget reservoir during forward steam drive operations. Reservoir Characteristics Geology The Winkleman Dome field is an asymmetrical surface anticlinal feature along the northwest end of the Wind River basin of Wyoming. The accumulation of oil is primarily a result of structural relief. There is both surface and subsurface evidence of faults trending in a northeast-southwest direction. This faulting probably had a minor influence on the oil probably had a minor influence on the oil accumulation. (Within the presently developed acreage, only one fault in the northern portion has had any significant effect on well performance.) The Nugget sandstone is of Jurassic age and generally is considered to be a blanket sand. Within the Winkleman Dome field the formation is divided into three benches separated by shaly lenses. Fig. 2 shows a typical sonic log through the Nugget formation, with permeability also plotted to illustrate the zonation. The productive limits of the reservoir are determined by structural position. Oil-water contact was determined from information on Well 50, which appears to be located near it. Rock and Fluid Properties Average values for the various reservoir parameters are listed in Table 1. The rock properties are based on cores from five wells, three of which were cored with oil. The sand has excellent porosity and permeability (at least for a Rocky Mountain reservoir, permeability (at least for a Rocky Mountain reservoir, although these factors are not quite so good as those associated with steam recovery projects in some California fields). Pay thickness for the reservoir was developed from sonic logs correlated with core analysis data. Fluid properties were obtained from samples collected at the wellhead. The crude is a dead, viscous, 14 deg. API gravity oil. The original reservoir pressure was 210 psig. The primary producing mechanism was water influx. P. 35