With proper engineering, liquid nitrogen can be used safely as a hydraulic fracturing fluid. The fluid's extremely cold temperature (-300 to -320°F) will induce thermal tensile stresses in the fracture face. These stresses exceed the tensile strength of the Devonian shale, causing the fracture face to fragment. Because of the extreme temperatures, treated water can be used as a diverter between fracturing stages. This water freezes instantly when it contacts the first treatment zone. This paper discusses the successful application of this technology to stimulate the Devonian shale in Eastern Kentucky. Introduction Liquid nitrogen has been applied in coal seams and sandstone reservoirs for the stimulation of gas production in the San Juan Basin of New Mexico. For nitrogen to be pumped safely into a well, the entire surface manifold and wellhead must be made of stainless steel. In some cases, operators may use free-hanging fiberglass tubing to protect the casing from extremely cold temperatures. Using liquid nitrogen as a fracturing fluid is a process that is in an early stage of development. Theoretically, self-propping fractures can be created by the thermal shock of an extremely cold liquid contacting a warm formation. As the fluid warms to reservoir temperature, its expansion from a gas to a liquid results in an approximate eightfold flow-rate increase. For example, a12-bbl/min liquid nitrogen flow can result in a flow rate as great as 96bbl/min some distance from the fracture. The Devonian shale, a thick formation beneath a large portion of Eastern Kentucky and West Virginia, has been described previously. This Devonian shale has a low permeability, is somewhat water-sensitive, and typically produces through natural fractures. Operators have used a number of different techniques to stimulate wells in the Devonian shale. However, stimulating these wells with a nitrogen-gas fracturing treatment is currently a common method. Fracturing this type of formation with cold liquid nitrogen rather than warm gas could prop fractures open more efficiently.
New techniques allow liquid nitrogen to be safely delivered to a moderate-depth formation at typical fracturing rates and at cryogenic temperatures (−320 to −232 F) while protecting the casing from damage. This process provides a high degree of thermal shock to the reservoir rock, creating adequate physical alteration of the fracture walls to prevent closure of hydraulically and/or thermally induced fractures. Additionally, thermal stress-induced microfractures that are orthogonal to the fracture plane will also occur. In general fracturing applications, severe thermal shock could seldom be achieved other than in a few applications of fracturing geothermal (nonhydrocarbon-bearing) reservoirs. The results of this field project indicate that the use of cryogenic nitrogen in refracture applications appears to be successful in reducing the damage from gel filter-cake residue of earlier fracturing treatments. There has been no evidence of any casing damage. This process has not been used on a nonfractured hydrocarbon zone. Introduction Thermal shock has been previously applied as a means to alter the physical conditions of reservoir rock and to stimulate hydrocarbon production. Before the development of techniques described in this paper, the maximum cooling effects that could be achieved were limited to those that could be obtained by pumping chilled brines >20 F) or liquid CO2 >0 F). Liquid nitrogen has a boiling point of −320 F at atmospheric pressure. Carbon steel alloys normally used for surface iron manifolding, wellhead configurations. and wellbore tubulars cannot withstand even very short-term exposure to cryogenic temperatures. For the new procedure, construction of special (all stainless-steel) surface piping, manifolding, and wellhead components prevented thermal contraction problems, and the use of free-hanging fiberglass tubing afforded protection to the casing from thermal shock damage. Four coalbed methane (CBM) wells (Wells A, B, C, and D) and a tight sandstone reservoir (Well E) were successfully fracture-stimulated with the use of cryogenic-nitrogen treatments. Standard oilfield nitrogen pumping units were modified to deliver either high-pressure liquid nitrogen or vaporized (warm) nitrogen gas. A technique for downhole diversion from one zone to another was also developed so that a second stage could treat a different part of the reservoir. Refracture treatments have been performed on five wells using these new techniques. Initial postfracture response was very good in all five wells, but only two wells appeared to provide long-term production enhancement. This process has not yet been applied as an initial stimulation treatment on a new well, because the operator was not drilling any new CBM wells at the time of the project. To protect the secrecy of the cryogenic-nitrogen treatment, the operator did not want to test the process on wells that it owned partly with other parties. Consequently. only wells that were wholly owned by the operator were chosen for the project. Observed Thermal Effects on Coal While a search was undertaken for a chemical. additive, or fluid that might have an advantageous effect on gas production from tight, low-rate CBM wells, coal samples were subjected to contact with and submerged in liquid nitrogen. The effects observed were that audible cracking sounds were heard while the samples were cooling down and warming back up. Measurements of the samples indicated significant shrinkage while cold. When competent coal samples came in contact with liquid nitrogen, the samples fractured and separated into smaller cubical units. Each time a coal sample contacted liquid nitrogen. the sample would break into smaller cubical units; repeated contact caused coal samples to continue to break into smaller cubical units. These observations were made at atmospheric pressure. P. 561^
To date, the art of effective openhole horizontal well fracturing is not well defined. Difficulties in regional sealing hamper the fracturing task, and results are generally suspect. Without proper isolation methods, the use of openhole horizontal well fracturing is limited. During many fracturing processes, including fracture acidizing, fracture or acid placement often occurs where fluid first contacts the borehole, often at the heel of the well. A new method is now available that combines hydrajetting and fracturing techniques. By using this new method, operators can position a jetting tool at the exact point where the fracture is required without using sealing elements. Unlike other techniques, this new method allows operators to place multiple fractures in the same well; these fractures can be spaced evenly or unevenly as prescribed by the fracture design program. Large-sized fractures can be placed with this method. Because the method is simple, operators can economically bypass damage by placing hundreds of small fractures in a long horizontal section. To enhance the process even more, operators can use acid and/or propped sand techniques to place a combination of the two fracture types in the well. This paper discusses the basic principles of horizontal hydrajet fracturing and how Bernoulli's theorem was used to design a hydrajet fracturing technique. Laboratory test results for the new technique are provided on Page 4. P. 263
Summary Foamed fluids are becoming very popular for use in stimulation treatments. This can be attributed to their excellent properties such as low leakoff rate, excellent proppant transport, longer fractures with less fluid, minimum formation damage, and superior posttreatment cleanup. Base fluids that can be foamed are oil, water. and acid. Foam quality is very critical to many of the properties of the resultant foam fluid. This quality changes with temperature and pressure. Included in this paper is a new approach to an easier determination of foam quality under bottomhole treating conditions so that necessary ratio adjustment can be made at the wellhead to obtain the desired quality at the formation. History The earliest foam fracturing treatment was performed in Jan. 1968. 1 This treatment placed approximately 2041 kg (4,500 lbm) of 12-/20-mesh glass bead proppant with an approximately 83 to 85%-quality foam to stimulate the Brown shale formation in Lincoln County, WV. Virtually no other use of foam stimulation fluids was reported until the latter half of 1973. At this time, there was a development, undercurrent of foam stimulation use that spread across the country and into Canadian operations. Papers presented by Blauer, Mitchell, and Kohlhaas in April 1974 and by Blauer and Kohlhaas in October 1974 served further to popularize this budding stimulation technique. Most foam fracturing treatments performed during 1973–76 were small volume, generally less than 189 m3 (50,000 gal), and carried some form of propping agent. Several other papers describing mechanical and design procedures for foam fracturing treatments appeared in 1975, 1976, and early 1977. Surprisingly, the site of the first massive foam stimulation treatment was the same general location as the first experimental treatment. In June 1976, a 946-m 3 (250,000-gal) foam fracturing treatment, which placed 135 715 kg, (299,200 Ibm) total sand. was performed in Lincoln County, WV. A second treatment comprising 1060 m3 (280,000 gal) foam and 140 432 kg (309,600 Ibm) total sand was performed in Nov. 1976, in the same West Virginia county. Both treatments were conducted as part of a joint Columbia Gas System Service Corp./ERDA demonstration of massive hydraulic fracturing in the Devonian shale. During, 1977–78, papers describing, variations in the established pattern in foam fracturing began to appear. Among these variations was extension of foam to fracture-acidizing applications. As a technique to reduce further the formation exposure to a potentially damaging aqueous fluid, a foamed methanol/water solution also was introduced at this time. Although there was evidence that the number of foam stimulation treatments was increasing, papers presented during 1979–80 gave an impression that this service was entering a period of consolidation or maturity. Counteracting this initial impression were several massive hydraulic fracturing services performed in cast Texas during the latter half of 1980. Treatments with volumes ranging, up to 2233 m3 (590,000 gal) of 65%-quality foam were performed. This largest job to date placed 503 487 kg (1,110,000 total lbm) of sand. Foam Quality Foam is a gas/liquid dispersion, with gas as the internal phase and liquid as the external phase. Foam quality is the ratio of gas volume to foam volume (volumetric gas content) at a given pressure and temperature. JPT P. 597^
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