Subterranean coal seams contain substantial quantities of natural gas, primarily in the form of methane. Such reservoirs are commonly referred to as coal-bed methane (CBM) reservoirs. To effectively produce gas from CBM reservoirs, one or more stimulation methods are used to increase the output.
The most common CBM stimulation methods include directionally drilling parallel to the bedding of the seam, the creation of a cavity in a coal seam, or hydraulic fracturing of the coal.
Directional drilling involves angling the drill stem so that drilling is not vertical but will parallel the coal seam. Because the bore hole trends along the formation, a greater area of the wellbore is in contact with the coal seam and thus higher gas extraction is possible.
The cavitation completion method creates on or more cavities in the coal. The purpose is to reduce the amount of damage to the surrounding structure that may have resulted during drilling, to create an enhanced permeability zone outside of the cavitated area, and to reduce the near wellbore flow resistance arising from the convergence of flow in a radially inward flow field. Typically cavity completions are performed on open-hole completed wells (no casing across the production interval) in a cyclic manner thus the treatment is usually referred to as cavitation cycling as described for example in: Palmer, I. D., Mavor, M. J., Spitler, J. L., Seidle, J. P., and Volz, R. F. 1993b. Openhole cavity completions in coalbed methane wells in the San Juan Basin. Journal of Petroleum Technology, 45(11):1072-1080 (November).
Compressed air is most frequently used to pressurize the near wellbore zone. These gases can be foamed to reduce their apparent mobility in the cleat network and contain them in the near wellbore region where they will be most effective. The pressure is bled off as fast as possible, rubblizing the near wellbore zone and producing it out of the wellbore, creating a rather large cavity surrounding the wellbore. The procedure reduces the wellbore skin effect.
Cavitation cycling uses several mechanisms to link the wellbore to the coal fracture system. These mechanisms include creating a physical cavity in the coals of the open-hole section (up to 10 feet in diameter); propagating a self-propping, vertical, tensile fracture that extends up to 200 feet away from the wellbore (parallel to the direction of maximum stress and perpendicular to the minimum principal stress); and creating a zone of shear stress-failure that enhances permeability in a direction perpendicular to the direction of least stress as described for example in: Khodaverian, M. and McLennan. 1993. Cavity completions: a study of mechanisms and applicability. Proceedings of the 1993 International Coalbed Methane Symposium (Univ. of Alabama/Tuscaloosa), pp. 89-97.
Cavitation is accomplished by applying pressure to the well using compressed air or foam, and then abruptly releasing the pressure. The over-pressured coal zones provide a pressure surge into the wellbore (a “controlled blowout”), and the resulting stress causes dislodgement of coal chips and carries the chips up the well. These cycles of pressure and blowdown are repeated many times over a period of hours or days, and the repeated alternating stress-shear failure in the coal formation creates effects that extend laterally from the wellbore as described for example in: Kahil, A. and Masszi, D. 1984. Cavity stress-relief method to stimulate demethanation boreholes. SPE Paper No. 12843, Proceedings 1984 SPE Unconventional Gas Recovery Symposium (Pittsburg).
Fracturing is another important method to enhance CBM production. As described for example in: Holditch, S. A. 1990. Completion methods in coal seam reservoirs. SPE 20670, Proceedings 65th SPE Annual Technical Conference (New Orleans), p. 533., typically hydraulic fracturing is performed on cased-hole perforated completion wells typically when the coal permeability is less than 20 mD. There are a great many variations of hydraulic fracturing coal formations, but in a rough approximation, the techniques involve injecting a fluid into the formation at sufficient pressure to initiate and propagate a hydraulic fracture, filling the fracture with proppant by continuing injection of a proppant laden fluid, and then flushing the treatment so that the proppant fills the fracture but not the wellbore. Olsen, et al., describe some additional considerations for fracturing coal-bed methane reservoirs in: Olsen, T. N., Brenize, G., and Frenzel, T.: “Improvement Processes for Coalbed Natural Gas Completion and Stimulation,” SPE 84122, presented at the SPE Annual Technical Conference and Exhibition, Denver (Oct. 5-8, 2003).
Conventional hydraulic fracturing technique is described in many literature sources, as well as when applied to coal rocks. Directional drilling cannot be considered as a pure stimulation technique. It is worth to note that both fracturing (either conventional fracturing or cavitation) and directionally drilling simply increases the amount of the coal seam which is in direct contact with the well bore, and, no technological method has been found yet to increase the original porosity of the formation.    Palmer, I. D., Mavor, M. J., Spitler, J. L., Seidle, J. P., and Volz, R. F. 1993b. Openhole cavity completions in coalbed methane wells in the San Juan Basin. Journal of Petroleum Technology, 45(11):1072-1080 (November).    Holditch, S. A. 1990. Completion methods in coal seam reservoirs. SPE 20670, Proceedings 65th SPE Annual Technical Conference (New Orleans), p. 533.    Palmer, I. D., Lambert, S. W., and Spitler, J. L. 1993a Coalbed methane well completions and stimulations. Chapter 14 in AAPG Studies in Geology 38, pp. 303-341.    Olsen, T. N., Brenize, G., and Frenzel, T.: “Improvement Processes for Coalbed Natural Gas Completion and Stimulation,” SPE 84122, presented at the SPE Annual Technical Conference and Exhibition, Denver (Oct. 5-8, 2003).    Khodaverian, M. and McLennan. 1993. Cavity completions: a study of mechanisms and applicability. Proceedings of the 1993 International Coalbed Methane Symposium (Univ. of Alabama/Tuscaloosa), pp. 89-97 or the above paper by Kahil, A. and Masszi, D. 1984.
Fracturing fluid leak-off through the cleat network during the fracturing process is a major limitation of modern hydraulic fracturing methods in CBM reservoirs. Fracturing fluid efficiency is the simple ratio of the volume of the created fracture at the end of pumping divided by the total volume of fluid injected to create the fracture. For obvious reasons, low fracturing fluid efficiency is undesirable. Expense and waste aside, the leaked off fluid can substantially reduce the permeability of the cleat network and defeat the benefit of the stimulation treatment. Moreover, due to various operational constraints (such as maximum injection pressure, maximum injection rate, cost, etc.) low fluid efficiency limits the fracture length that may be achieved.
Fracturing fluids injected into CBM reservoirs create a complex fracture comprised of some dominant channel and numerous minor channels. The minor channels may be part of the cleat network. High leak-off of the fracturing fluid through the cleat network reduces both the rate of growth of the main fracture and the maximum fracture length. Injecting the fracturing slurry at higher flow rates can compensate for leak-off losses, but the leaked off fluid may be trapped in the cleats, blocking the pathway through which reservoir fluids can flow from the reservoir to the wellbore. The cleat aperture can be too small for proppant to enter and prop the cleats in normal practice. Recently, fracturing fluids have been developed that are non-damaging to cleats. Whilst leaking off into the cleat network, they are free of macro-molecules that create immobile plugs in the cleats. Thus, because they are free of polymers and insoluble solids, the non-damaging filtrate is easily displaced from the cleats when the well is put on production. Olsen et al above describe such a fracturing fluid.
It is also known to use water-based fluids with dewatering aids and proppant. The presence of water in a porous medium reduces the flow capacity of that medium to other immiscible fluids such as oil or gas. In the case of CBM reservoirs, water from the injected hydraulic fracturing fluids can infiltrate the cleat network and negatively impact the surface properties (mainly wettability) of the coal. These changes can result in reduced dewatering and lead to coal fines migration, which can plug the cleats. U.S. Pat. No. 5,229,017, by Nimerick and Hinkel, describes chemicals, such as butoxylated glycols, that adsorb onto coal surfaces, rendering them hydrophobic. The hydrophobic coal surface maintains the original surface properties of the coal and hinders re-wetting and re-absorption of surfactant present in the fracturing fluid. These surfactants are delivered in the fracturing fluid and result in more rapid coal dewatering and fracturing fluid recovery out of the fracture.
Other known techniques attempt to control the leak-off into cleats. For example, U.S. Pat. No. 5,474,129 describes a process of using injected gases to perform cavity completions. Water with a foaming agent is added to the gas to create a foam downhole. The foam reduces the rate of gas leaking away from the wellbore through the cleat network. Instead, gas is trapped in the near wellbore region where it adsorbs into the near wellbore coal. Upon depressurization, the trapped gas expands and destroys the coal fabric and promotes the cavity completion process. This patent is referenced because it identifies the role of the cleats in conducting fluids away from a source. Foamed fracturing fluids are often used in CBM reservoirs to control leak-off, to reduce the hydrostatic head in the wellbore at the end of the treatment (and improve fracturing fluid recovery), and to reduce the amount of damaging polymers that enter the cleat network.
Methods of enhancing coal-bed methane production are considered enhanced recovery techniques. Enhanced recovery techniques involve flooding the CBM reservoir with gases that adsorb to coal more strongly than methane, and thus displace methane or lighter hydrocarbones from the micropore structure of the coal. Several papers describe various aspects of this technique including:    Fulton, P. F., Parente, C. A., Rogers, B. A.: “A Laboratory Investigation of Enhanced Recovery of Methane from Coal by Carbon Dioxide Injection,” SPE/DOE 8930, presented at the 1980 SPE/DOE Symposium on Unconventional Gas Reservoirs, Pittsburg (May 18-21, 1980);    Chaback, J. J., Morgan, D., and Yee, D.: “Sorption Irreversibilities and Mixture Compositional Behavior During Enhanced Coal Bed Methane Recovery Processes,” SPE 35622, presented at the Gas Technology Conference, Calgary (Apr. 28-May 1, 1996);    Zhu, J., Jessen, K., Kovscek, A. R., and Orr, F. M.: “Analytical Theory of Coalbed Methane Recovery by Gas Injection,” SPE Journal, pp 371-379 (December 2003); or    Gorucu, F. B., Jikich, S. A., Bromhal, G. S., Sams, W. N., Ertekin, T., and Smith, D. H.: “Matrix Shrinkage and Swelling Effects on Economics of Enhanced Coalbed Methane Production and CO2 Sequestration in Coal,” SPE 97963, presented at the 2005 SPE Eastern Regional Meeting, Morgantown (Sep. 14-16, 2005).
The use of liquid gas fracturing with proppant with mixtures of carbon dioxide and nitrogen or only carbon dioxide is published in general and is used for example in Canada and in the Eastern United States for shallow gas well stimulation. Liquid CO2 or foams/emulsions created by mixtures of CO2 and nitrogen are reported to be undamaging because the fluid will vaporize and be produced after the treatment. Descriptions of the known methods can be found for example in:    Lillies, A. T., and King, S. R.: “Sand Fracturing with Liquid Carbon Dioxide,” SPE 11341, presented at the SPE Production Technology Symposium, Hobbs (Nov. 8-9, 1982);    Yost, A. B., Mazza, R. L., and Gehr, J. B.: “CO2/Sand Fracturing in Devonian Shales,” SPE 26925, presented at the SPE Eastern Regional Meeting, Pittsburg (Nov. 2-4, 1993);    Mazza, R. L.: “Liquid-Free CO2/Sand Stimulations: An Overlooked Technology—Production Update,” SPE 72383, presented at the SPE Eastern Regional Meeting, Canton (Oct. 17-19, 2001); and    Cambell, S. M., Fairchild, N. R., and Arnold, D. L.: “Liquid CO2 and Sand Stimulations in the Lewis Shale, San Juan Basin, New Mexico: A Case Study,” SPE 60317, presented at the SPE Rocky Mountain Regional/Low-Permeability Reservoirs Symposium and Exhibition, Denver (Mar. 12-15, 2000).
Once the appropriate bore hole(s) is completed by using one of the above methods, dewatering must occur to reduce the pressure in the formation. Pressure drop in turn promotes methane release from within the coal into the cleats. If the cleats contain a high enough permeability, that is, inter-connectivity, then the methane will flow from the coal into the well bore and can be extracted.
In U.S. Pat. No. 6,412,559, there is described a process of stimulating and enhancing methane production in coal reservoirs. The process uses a stronger adsorbing gas (SAG, stronger than methane such as carbon dioxide or H2S), which swells the formation during the fracturing process, the key element of their process is repeated SAG injection and shut-in steps after the stimulation treatment. The shut-in steps may be between 1 day and 1 year in length. The principle reason for the use of a SAG is to promote enhanced coal-bed methane recovery as the SAG preferentially adsorbs onto the coal and displaces adsorbed methane. The fracturing is employed at the beginning of the repeated SAG injection and shut-in steps to improve the infectivity of the SAG, i.e., the fracturing step is to reduce wellbore skin and enable improved CO2 injection.
In the published US patent application 20050082058 the reaction of a predetermined gas with the coal is used to induce shrinkage within the coal matrix, thus reducing effective stress and enhancing the fracture void volume. This increased fracture void volume increases coal-bed permeability and resultant increase in methane gas flows. It also allows placement of proppant within the coals to maintain open fractures in the regions surrounding the propped fracture, thus allowing the enhanced fracture system to communicate more effectively with both the natural fracture system and the wellbore and aiding methane recovery.
In the U.S. Pat. No. 5,014,788 there is described a method to improve production by introduction of a swelling gas into the coal which after release generates uneven stress fractures. The emphasis of the known method is in the “relatively rapid reduction” in the pressure.