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Abstract This case history paper describes a technique that minimizes the creation of multiple fractures in deep coal seams during hydraulic fracturing operations. The technique enabled the operator and the service company to perform 24 nitrogen foam-fluid fracturing treatments in 33 days in the Upper Silesian basin (Poland). The creation of multiple fractures is a phenomenon often encountered during fracturing operations in coal seams and is the most probable cause of early screenouts. During this fracturing campaign, early screenouts were observed at sand concentrations less than 3 lb/gal. These screenouts were attributed to a lack of fracture width caused by the presence of multiple fractures, including possible horizontal fracture components or tortuosity. The operator and the service company developed a technique that involves pumping a small volume of highly viscous crosslinked gel before the main fracturing treatment. This technique prevented early screenouts and allowed the higher sand concentrations to be pumped. Introduction The operator won a concession to explore for coalbed methane in the Upper Silesian Basin of southern Poland in September 1993 (Figure 1). Following negotiation of various terms, the concession became effective in late August 1994 and drilling commenced in November 1994. The project targeted the coal-bearing strata of the Carboniferous era. Various seams of these strata have been actively mined for over one-hundred years in this area of Poland, with numerous shows of gas, fires and explosions. The concession consists of 487 km2 just south of the town of Katowice with active coal mines immediately to the east of the concession, and one active coal mine (Silesia Mine) surrounded by the concession area (Figure 2). The objective of this work was to sample the coalbed methane productivity of the concession in order to determine the economic potential for a development project that would consist of a couple hundred wells. The stratigraphy in the area consists of over 60 coal seams of 0.5-m or greater thickness over an approximately 1000-m interval. A statistical sampling was needed because of three reasons:–the mandate to evaluate the resource in a period of less than three years with a total of only 15 wellbores –the significant amount of coal –the anticipated variability of various coalbed methane parameters such as gas capacity, saturation, permeability, and production rate Based on the operator's experience in the San Juan and Warrior Basins, fracture stimulations were the preferred completion method for coalbed methane wells. Historically there had been very few fracture stimulations performed in Poland. and no fracturing equipment or experienced crews were available. With respect to perforating, there was no referencing of performance data to API standards. Thus the project needed to import these services with the associated high mobilization charges. Because of this high fixed-cost component, individual seam or zone completions were too costly and multiple-zone well completion campaigns were chosen. To reduce mobilization costs, a campaign approach for treating the selected intervals was chosen. This paper describes which problems were encountered during a campaign that involved treating 24 intervals in six of the eight test wells and how these problems were solved. The original plan for evaluation of the concession provided for seven coreholes to determine the basic gas capacity and isotherm information, and eight test wells for production testing. P. 161^
McDaniel, B.W. (Halliburton Energy Services Inc.) | Grundmann, Steven R. (Halliburton Energy Services Inc.) | Kendrick, William D. (Halliburton Energy Services Inc.) | Wilson, Dennis R. (Conoco Inc.) | Jordan, Scott W. (Conoco Inc.)
Abstract 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^
Abstract The presence of methane in groundwater in areas where shale gas resources are being developed has at times been incorrectly attributed to hydraulic fracturing activities, often due to the difficulty in distinguishing anthropogenic methane from methane naturally present in groundwater. This presentation will summarize the results of a study for development of forensic tools to distinguish natural from anthropogenic methane in the Marcellus Shale area. Analytical data for more than a thousand pre-drill water samples from the Marcellus Shale area has been reviewed and evaluated statistically to investigate potential correlations with observed methane concentrations in groundwater. Results of the study indicated that natural methane concentrations could be correlated to several natural environmental factors, including the ionic composition of the groundwater and the topographic location of the water well. In combination with other lines of evidence, these parameters can be used to distinguish natural from anthropogenic methane. Distinguishing natural from anthropogenic sources of methane in groundwater is particularly important because residential groundwater wells are used for water supply in many areas where hydraulic fracturing is used to stimulate shale gas production. In fact, the preoccupation with impacts to groundwater from hydraulic fracturing activities is not limited to the U.S., as the issue is being frequently raised in other regions with great shale gas potential, such as Mexico, Argentina, Colombia, and the European Union. The findings of the study provide a framework that can be applied at other site to assess the potential impacts of hydraulic fracturing to groundwater resources.
Methane gas from wells completed exclusively in coal seams has become a major energy resource in the USA, and it is being evaluated in many other countries. In all but a very few cases, stimulation by hydraulic fracturing is required for adequate production rates. The application of fracturing to improve degasification of coal beds prior to mining began in 1974, but in recent years its application has expanded such that many completions are independent of any expected future mining operations. Wells are often completed in multiple coal seams with possibly hundreds of feet between the completion zones.
The hydraulic fracturing fluids, equipment, and designs used for coalbed methane wells have seen major evolutionary changes from the early treatments when completing in seams to be mined. When fracturing became common in coal seams where mining was not being considered, roof integrity was no longer a concern and the treatment designs began to undergo more accelerated changes.
This paper will trace the historical application of hydraulic fracturing in the two major commercial coalbed methane producing areas: The Black Warrior Basin of Northern Alabama and the San Juan Basin of Northwest New Mexico/Southwest Colorado. Recent applications in the Raton and Piceance Basins of Colorado and the Central Appalachian Basin will also be addressed.
Conventional fracturing technology cannot always be directly applied to fracturing coal seams. Coal is a reservoir rock that has many unusual characteristics, such as: 1. Wide variety of treating pressures, often abnormally high, with pressure gradients commonly above 1.0 psi/ft (even though most pressure gradients commonly above 1.0 psi/ft (even though most believe vertical fractures are still the predominant occurrence). 2. The very high leakoff of the fracturing fluid into the coal cleat system and coal's mechanical response are not well modeled by the mathematics used in conventional design simulators for sandstones and carbonate reservoirs. 3. The mechanism of methane production is quite different from traditional gas reservoirs. 4. Postcompletion problems of coal and proppant production are added difficulties.
Although not the only anomalies associated with completing coalbed methane (CBM) wells, the points listed above have been the dominant factors which have influenced the way fracturing has been applied as part of the completion procedure. When early fracturing treatments were performed in seams to be mined, safety concerns over cavings from a weakened mine tool would often have the effect of limiting pump rate, fluid volume, or fluid viscosity. These concerns could often lead to very limited effectiveness of the stimulation treatment.
Mining operations allowed the industry some firsthand observations of the resultant fractures. Beginning in 1974 and continuing through present operations, many investigators have had the opportunity to study some areas where the fracture(s) occurred within the coal seams. Diamond and Oyler presented an excellent report on 22 government-sponsored mineback investigations following fracturing treatments. However, we must use discretion in our application of these observed results. The response seen in seams only a few hundred feet deep may not always be an accurate indication of what will occur within more deeply buried coal seams. At shallow depths, there is a higher probability that the two horizontal stress components may be of similar magnitude. This will lessen the probability of achieving a single biwing planar vertical fracture. probability of achieving a single biwing planar vertical fracture. Current coal completions typically involve depths of 1000 to 4000 ft. More shallow coals are occasionally included, and many operators are evaluating the economic potential of deeper seams.
Tax Credit Effects
During the mid 1980's the industry began to seriously consider coal seams as a commercial gas reservoir. The classification of coalbed methane as an "unconventional gas" offered operators a significant tax credit, which greatly improved the economics of coal wells. Crouse gives a good discussion of the effects of this tax incentive, including economic comparison for Fruitland coal seam gas production with and without the tax credit. production with and without the tax credit. Drilling activity in 1990 reached a level few had imagined possible only a few years earlier. Possibly the greatest leap in proven possible only a few years earlier. Possibly the greatest leap in proven reserves of coalbed methane occurred during 1988.