Optics: measuring and testing – For light transmission or absorption – By comparison
Reexamination Certificate
2002-10-09
2004-01-13
Font, Frank G. (Department: 2877)
Optics: measuring and testing
For light transmission or absorption
By comparison
C356S436000, C250S256000, C250S269100
Reexamination Certificate
active
06678050
ABSTRACT:
TECHNICAL FIELD
This invention relates to in-situ methods of measuring or analyzing dissolved, free, or embedded substances with a spectrometer and an apparatus to carry out the method. In particular this invention relates to a method and apparatus of analyzing substances down a well. More particularly, this invention relates to a method and apparatus to detect, analyze and measure methane or related substances in subsurface coal bed formations using a portable optical spectrometer to thereby predict a potential methane production of the well.
BACKGROUND AND SUMMARY OF THE INVENTION
Coal bed methane is methane that is found in coal seams. Methane is a significant by-product of coalification, the process by which organic matter becomes coal. Such methane may remain in the coal seam or it may move out of the coal seam. If it remains in the coal seam, the methane is typically immobilized on the coal face or in the coal pores and cleat system. Often the coal seams are at or near underground water or aquifers, and coal bed methane production is reliant on manipulation of underground water tables and levels. The underground water often saturates the coal seam where methane is found, and the underground water is often saturated with methane. The methane may be found in aquifers in and around coal seams, whether as a free gas or in the water, adsorbed to the coal or embedded in the coal itself.
Methane is a primary constituent of natural gas. Recovery of coal bed methane can be an economic method for production of natural gas. Such recovery is now pursued in geologic basins around the world. However, every coal seam that produces coal bed methane has a unique set of reservoir characteristics that determine its economic and technical viability. And those characteristics typically exhibit considerable stratigraphic and lateral variability.
In coal seams, methane is predominantly stored as an immobile, molecularly adsorbed phase within micropores of the bulk coal material. The amount of methane stored in the coal is typically termed the gas content.
Methods of coal bed methane recovery vary from basin to basin and operator to operator. However, a typical recovery strategy is a well is drilled to the coal seam, usually a few hundred to several thousand feet below the surface; casing is set to the seam and cemented in place in order to isolate the water of the coal from that of surrounding strata; the coal is drilled and cleaned; a water pump and gas separation device is installed; and water is removed from the coal seam at a rate appropriate to reduce formation pressure, induce desorption of methane from the coal, and enable production of methane from the well.
Assessment of the economic and technical viability of drilling a coal bed methane well in a particular location in a particular coal seam requires evaluation of a number of reservoir characteristics. Those characteristics include the gas content and storage capability of the coal; the percent gas saturation of the coal; the gas desorption rate and coal density, permeability, and permeability anisotropy; and gas recovery factor.
While industry has developed methods to enhance production from formations that exhibit poor physical characteristics such as permeability and density, currently no practical methods are available to increase the gas content of a coal seam. Thus, identifying coal seams that contain economic amounts of methane is a critical task for the industry. The primary issue in identifying such coal seams involves developing a method and apparatus to quickly and accurately analyze coal seams for gas content.
Currently accepted methods of measuring gas content involve extracting a sample of the coal from the seam and measuring the amount of gas that subsequently desorbs, either by volume or with a methane gas sensor. However, collection of the coal sample usually changes its gas content to a significant extent before gas desorption is monitored. This degradation of sample integrity leads to degradation of the data collected. That degradation of data creates significant doubt in the results of those common methods. As well, because these methods hinge on waiting for the methane to desorb from the coal, they require inordinate amounts of time and expense before the data is available.
Downhole sensing of chemicals using optical spectroscopy is known for oil wells. For example, Smits et. al., “In-Situ Optical Fluid Analysis as an Aid to Wireline Formation Sampling”, 1993 SPE 26496, developed an ultraviolet/visible spectrometer that could be placed in a drill string. That spectrometer was incorporated in a formation fluid sampling tool whereby formation fluids could be flowed through the device and analyzed by the spectrometer. That spectrometer was largely insensitive to molecular structure of the samples, although it was capable of measuring color of the liquids and a few vibrational bond resonances. The device only differentiates between the O—H bond in water and the C—H bond in hydrocarbons and correlates the color of the analyte to predict the composition of the analyte. The composition obtained by the device is the phase constituents of the water, gas and hydrocarbons. By correlating observation of gas or not gas with observation of water, hydrocarbon, and/or crude oil, the instrument can distinguish between separate phases, mixed phases, vertical size of phases, etc. By correlating the gas, hydrocarbon, and crude oil indicators, the instrument can presumably indicate if a hydrocarbon phase is gaseous, liquid, crude, or light hydrocarbon. A coal bed methane well with varying hydrocarbons from coal to methane and, possibly, bacterial material, provides an environment too complex for such a device to differentiate methane and the other substances of interest. The device is not capable of resolving signals from different hydrocarbons to a useful extent, and the device is not capable of accurate measurements needed for coal bed methane wells. Furthermore, the requirements that the sample be fluid, that analysis occur via optical transmission through the sample, and that the sample be examined internal to the device precludes its use for applications such as accurately measuring gas content of coal seams.
In other apparatuses known in U.S. Pat. No. 4,802,761 (Bowen et. al.) and U.S. Pat. No. 4,892,383 (Klainer, et. al.), a fiber optic probe is positioned to transmit radiation to a chemically filtered cell volume. Fluid samples from the surrounding environment are drawn into the cell through a membrane or other filter. The fiber-optic probe then provides an optical pathway via which optical analysis of the sample volume can be affected. In the method from Bowen et. al., a Raman spectrometer at the wellhead is used to chemically analyze the samples via the fiber optic probe. The method allows purification of downhole fluid samples using chromotographic filters and subsequent analysis of the fluid and its solutes using Raman spectroscopy. However, the stated requirement that the Raman spectrometer be remote from the samples of interest and that it employ fiber-optic transmission devices for excitation and collection ensures that the sensitivity of the device is limited. The device further does not consider the conditions present in subsurface wells when analyzing the samples. Furthermore, as in the Smits et. al. case, the requirements in Bowen et. al. and Klainer et. al. that the sample be fluid and that the sample be examined internal to the device significantly decrease the utility of the device for applications such as measuring gas content of coal seams.
Methods of sample preparation and handling for well tools have been described, as well. In U.S. Pat. No. 5,293,931 (Nichols et. al.), an apparatus is disclosed for isolating multiple zones of a well bore. The isolation allows isolated pressure measurements through the well bore or wellhead collection of samples of fluids from various positions in the wellbore. However, such wellhead sample collection degrades sample integrity and does not provide a practical method or appa
Herries John
Pope John
Crowell & Moring LLP
Font Frank G.
Nguyen Sang H.
WellDog, Inc.
LandOfFree
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