Apparatus for monitoring pressure using capillary tubing
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An apparatus for monitoring the pressure in a gas well at a downhole location is disclosed. The apparatus uses a capillary tube connecting a downhole monitoring assembly with a pressure gauge or gauges at the wellhead. The downhole monitoring assembly and capillary tube are located externally to the production tube so as not to block the production tube for cleaning or other uses. A passage from the interior of the production tube passes gas to the capillary tube in order to measure the pressure at the downhole end of the production tube.

Conrad, Greg Allen (Pocola, OK, US)
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What is claimed is:

1. An apparatus for monitoring downhole pressure in a well, comprising: (a) a production tube comprising a downhole end, and further comprising an exterior and interior; (b) a capillary tube comprising a wellhead end and a downhole end, wherein said capillary tube is positioned to said exterior of said production tube; (c) a monitor tip adjacent to said exterior of said production tube, said monitor tip positioned near said downhole end of said production tube and in communication with said downhole end of said capillary tube; and (d) a pressure gauge in communication with said wellhead end of said capillary tube.

2. The apparatus of claim 1, wherein said monitor tip comprises a filter in communication with said downhole end of said capillary tube.

3. The apparatus of claim 2, further comprising a passage between said filter and said interior of said production tube whereby gas may pass from said interior of said production tube to said filter and into said capillary tube.

4. The apparatus of claim 3, further comprising a fitting connecting said tip and said downhole end of said capillary tube.

5. The apparatus of claim 3, further comprising a plurality of bands binding said capillary tube and said production tube together, said bands spaced along the length of said capillary tube.

6. The apparatus of claim 1, wherein said pressure gauge comprises a transmitter operable to send a pressure reading to a remote location.

7. The apparatus of claim 1, wherein said pressure gauge comprises a mechanical pressure gauge and a transmitter operable to send a pressure reading to a remote location.



This application claims the benefit of U.S. provisional patent application No. 60/655,854, filed Feb. 23, 2005.

The present invention relates to pressure monitoring systems for gas wells, and in particular to an apparatus for monitoring the pressure at the bottom of a gas well by means of a capillary tube external of the well's production tube.

It has long been recognized that coalbeds often contain combustible gaseous hydrocarbons that are trapped within the coal seam. Methane, the major combustible component of natural gas, accounts for roughly 95% of these gaseous hydrocarbons. Coal beds may also contain smaller amounts of higher molecular weight gaseous hydrocarbons, such as ethane and propane. These gases attach to the porous surface of the coal at the molecular level, and are held in place by the hydrostatic pressure exerted by groundwater surrounding the coal bed.

The methane trapped in a coalbed seam will desorb when the pressure on the coalbed is sufficiently reduced. This occurs, for example, when the groundwater in the area is removed either by mining or drilling. The release of methane during coal mining is a well-known danger in the coal extraction process. Methane is highly flammable and may explode in the presence of a spark or flame. For this reason, much effort has been expended in the past to vent this gas away as a part of a coal mining operation.

In more recent times, the technology has been developed to recover the methane trapped in coalbeds for use as natural gas fuel. The world's total, extractable coal-bed methane (CBM) reserve is estimated to be about 400 trillion cubic feet. Much of this CBM is trapped in coal beds that are too deep to mine for coal, but are easily reachable with wells using drilling techniques developed for conventional oil and natural gas extraction. Recent spikes in the spot price of natural gas and the positive environmental aspects of the use of natural gas as a fuel source have hastened the development of CBM recovery methods.

The first research in CBM extraction was performed in the 1970's, exploring the feasibility of recovering methane from coal beds in the Black Warrior Basin of northeast Alabama. CBM has been commercially extracted in the Arkoma Basin (comprising western Arkansas and eastern Oklahoma) since 1988. As of March 2000, the Arkoma Basin contained 377 producing CBM wells, with an average yield of 80,000 cubic feet of methane per day. Today, CBM accounts for about 7% of the total production of natural gas in the United States.

Although a significant amount of CBM is still extracted through vertical drilling methods, horizontal drilling methods have become more common. The general techniques for horizontal drilling are well known, and were developed for conventional extraction of oil and natural gas. In the usual case, the well begins into the ground vertically, then arcs through some degree of curvature to travel in a generally horizontal direction. Horizontal wells thus contain a bend or “elbow,” the severity of which is determined by the drilling technique used. It is believed that horizontal drilling may result in better extraction rates of CBM from many coal beds due to the way in which coalbeds tend to form in long, horizontal strata. One analysis has shown that “face” cleats in coalbeds appear to be more than five times as permeable as “butt” cleats, which form orthogonally to face cleats. A horizontal well can increase productivity by orienting the lateral section of the well across the higher-permeability face cleats. As a result of these effects, the area drained by a horizontal well may be effectively much larger than the area drained by a corresponding vertical well placed into the same coalbed stratum. Horizontal well CBM extraction thus promises greater production from fewer wells in a given coalbed. The first horizontally drilled CBM wells in the Arkoma Basin were put in place around 1998.

Another developing area for the recovery of natural gas from unconventional sources is the extraction of natural gas from sandstone deposits. Sandstone formations with less than 0.1 millidarcy permeability, known as “tight gas sands,” are known to contain significant volumes of natural gas. The United States holds a huge quantity of these sandstones. Some estimates place the total gas-in-place in the United States in tight gas stands to be around 15 quadrillion cubic feet. Only a small portion of this gas is, however, recoverable with existing technology. Annual production in the United States today is about two to three trillion cubic feet. Many of the same problems presented in CBM extraction are also faced by those attempting to recover natural gas from tight gas sands, and thus efforts to overcome problems in CBM extraction may be directly applicable to recovery from tight gas sands as well.

One of the numerous obstacles to the efficient and profitable recovery of gas from unconventional sources is the estimation of gas reserves in a particular field. Estimation of gas reserves is important in order to ensure that a particular well is profitably operated throughout its life. Most approaches to gas reserve calculations treat the process as a continuous one, whereby estimated reserves are recalculated over the life of a producing gas well or field. In the early stages of development, reserve estimates may be based largely or entirely upon volumetric calculations. This approach involves the determination of the physical size of a reservoir, pore volume within the mineral matrix of the field, and the gas content within the matrix. A recovery factor is then applied, based on experience with the type of field in question, against the total hydrocarbons-in-place estimate. All of the factors used in these calculations involve estimated values, that when multiplied together create significant uncertainties in the gas reserve estimation process.

As production data from a field or well become available over an initial period of operation, more accurate techniques for gas reserve estimation may be used. Such methods include decline analysis and material balance calculations. These methods are generally more accurate in oil fields, where bottom-hole pressures are typically fixed, and less accurate in gas fields where wellhead back-pressures tend to fluctuate significantly. Nevertheless, these approaches may represent the best available approaches to the pursuit of good gas reserve estimates.

The principle behind decline analysis is the fitting of empirically derived curves to daily or monthly production data in order to forecast future production and predict recoverable reserves. Earlier decline analysis techniques depended only upon flow information, but, as explained more fully below, more sophisticated techniques in use today may also take into account the flowing pressure of gas. Flowing pressure is most accurately measured at the downhole end of the production tube, just above the location of the packer.

The most common decline curve analysis is the exponential decline. In unconventional fields where relatively low production results are expected, however, hyperbolic and harmonic curves may also be used in specific cases where these curves are known to produce better results. The hyperbolic curve, in particular, has been used to model the later stages of production from CBM wells, where significant reserves may remain but the remaining gas is produced at very low pressure levels. The use of a standard exponential decline in these circumstances may result in an inaccurately pessimistic evaluation of gas reserves.

Material balance calculations are perhaps more often used than decline analysis for gas reserves. This approach is based on the non-ideal gas law, PV=ZnRT, where Z is a factor adjusting for the non-ideal state of the gas. If a reservoir comprises a closed system and contains a single-phase gas, the pressure in the reservoir will decline proportionately to the amount of gas produced. Bottom water drive in gas reservoirs, however, contributes to the depletion mechanism, which degrades the accuracy of this approach.

When either of these methods are used, two calculation procedures may be applied. The deterministic calculation procedure is far more common. In the deterministic procedure, a single value for each parameter is input into an appropriate equation to obtain a single answer. By contrast, in a probabilistic approach a distribution curve is employed for each parameter and, through the use, for example, of a Monte Carlo simulation, a distribution curve for the answer can be developed. Statistical techniques can then be applied to this distribution curve to determine, for example, the minimum and maximum estimated gas reserve values, the mean value, the medial value, the mode value, and the standard deviation. All of this data may prove helpful in the ultimate calculation of expected gas reserves on a continuing basis.

Gas wells, and, as already noted, particularly unconventional wells, create special problems with any of these gas reserve calculation approaches. First, gas wells usually do not flow at a constant bottom hole pressure throughout their lives. CBM wells in particular may actually exhibit a negative decline during their early production phase due to the dewatering effect, particularly when additional wells are added in a high permeability region. These issues make gas reserve calculation in unconventional wells particularly difficult.

In order to partially compensate for the difficulty of calculating gas reserves in unconventional gas wells or fields, gas flowing pressure may be used as part of a decline analysis. Since production rates vary proportionally with the flowing pressure drop, dividing the production rates by the associated drop in flowing pressure is an effective method for normalizing production data. This normalized rate may be plotted against a function defined as the amount of time it would take to produce the current cumulative production at the current rate. The rate is thus defined as cumulative production divided by flow rate. As a result of using this function, constant rate and constant pressure production can be made to appear the same in the gas reserve calculation, and more accurate results may be obtained.

Another important factor in gas reserve analysis, applicable particularly to decline analysis, is the observation that gas compressibility is a very strong function of reservoir pressure. Compressibility describes the amount of volume of a fluid that may be moved with a given change in pressure. This is critical to a determination concerning gas reserves, because it describes the energy in the gas that allows it to be driven from the reservoir in the first place. As already explained, unconventional gas wells tend to produce at very low pressure, particularly in the later stages of their lifetimes. Gas compressibility increases as pressure decreases, and thus there are increasing amounts of reservoir energy available as the reservoir is depleted. Iterative calculations are necessary in order to track this effect as a well produces.

It may be seen from this discussion that while gas reserve estimation is difficult, particularly with regard to wells and fields associated with unconventional gas sources, the estimation process is greatly aided by the provision of continuous gas pressure data from the well. While the art includes numerous methods of determining gas pressure either at the wellhead or downhole, none of these prior art techniques is particularly well adapted for use in generating continuous downhole pressure data for use in gas reserve calculations. U.S. Pat. No. 4,414,846 to Dublin, Jr. et al. teaches a gas well monitoring device with a sensing unit at the well head. The device samples pressure and temperature of gas at the well head, and by means of electronic circuitry calculates an estimated downhole pressure. The art also includes devices with downhole sensors that are installed within the production tubing of a well, such as shown in U.S. Pat. No. 6,257,332 to Vidrine et al. and U.S. Pat. No. 6,464,004 to Crawford et al. It is believed that readings taken at the wellhead are not as accurate as pressure readings taken at the downhole end of the wellbore. Devices that enter the production tubing of a well will interfere with other equipment in the well. This is a particularly critical issue with regard to CBM wells, where the presence of coal fines and persistent plugging require frequent swabbings of the production tube. What is desired then is an apparatus for measuring pressure on an ongoing basis at the end of a gas well, whereby the measuring system is simple to operate and maintain and does not interfere with other production and maintenance equipment in the well.


The present invention is directed to an apparatus for continuously monitoring the flowing bottom hole pressure of a gas well. The invention is particularly well suited to use in CBM and other unconventional gas well configurations. The invention utilizes a capillary tube that runs along the exterior of the production tubing for the well. In this manner the delicate instrumentation associated with the measurement may be located at the other end of the capillary tube, preferably at the well head. This reduces the likelihood of damage or loss to sensitive instrumentation during use. It also simplifies maintenance with respect to the invention, since the tubing need not be removed if there is a need to replace or calibrate instrumentation.

Since the capillary tube is strung along the outside of the production tubing, it does not interfere with any other equipment that may be used during the operation and production phases of the well. A monitor tip serves to protect the end of the tubing during insertion and operation. Even though the monitor tip and capillary tube are located to the exterior of the production tube, the gas pressure is still taken at the interior of the downhole end of the production tube by means of a passage between the interior of the production tube and the monitor tip. In this way the most accurate downhole pressure reading may be made available.

It may be seen then that in one aspect of the invention is provided an apparatus for monitoring downhole pressure in a well, comprising a production tube comprising a downhole end, and further comprising an exterior and interior; a capillary tube comprising a wellhead end and a downhole end, wherein said capillary tube is positioned to said exterior of said production tube; a monitor tip adjacent to said exterior of said production tube, said monitor tip positioned near said downhole end of said production tube and in communication with said downhole end of said capillary tube; and a pressure gauge in communication with said wellhead end of said capillary tube.

It is therefore an object of the present invention to provide for a pressure monitoring apparatus and method that directly detects pressure at the bottom of a gas well.

It is a further object of the present invention to provide for a pressure monitoring apparatus and method that does not block the interior of the production tubing in a gas well.

It is also an object of the present invention to provide for a pressure monitoring apparatus and method that is easily maintained.

These and other features, objects and advantages of the present invention will become better understood from a consideration of the following detailed description of the preferred embodiments and appended claims in conjunction with the drawings as described following:


FIG. 1 is an elevational view of a downhole tube assembly and production tubing segment according to a preferred embodiment of the present invention.

FIG. 2 is an elevational, partial cut-away, partial exploded view of a downhole tube assembly according to a preferred embodiment of the present invention.

FIG. 3 is an elevational view of a well head assembly according to a preferred embodiment of the present invention.


With reference to FIG. 1, downhole subassembly 10 of a preferred embodiment of the present invention may be described. Downhole subassembly 10 is preferably designed for deployment at or near the end of a production tube for placement in a well, just above the position for placement of the borehole packer. Downhole subassembly 10 is composed of production tube segment 12 and monitor tip 14. In the preferred embodiment, production tube segment 12 is a tube constructed of steel or other appropriately strong material, threaded to fit into other segments of the well production tube (shown in dotted lines in FIG. 1). In the preferred embodiments, production tube segment 10 is sized to fit either of the most common 2⅜ inch or 2⅞ inch production tube sizes used in CBM extraction. In alternative embodiments, other sizes may be accommodated. In the preferred embodiment, the hollow interior of production tube segment 12 is kept clear in order to minimize blockage and facilitate periodic swabbing and cleaning.

Attached to production tube segment 12 by welding or other appropriate means is monitor tip 14. Monitor tip 14 protects the downhole entry point for gas in order to facilitate an accurate reading, as will be described more fully herein. Like production tube segment 12, monitor tip 14 may be constructed of steel or another appropriately strong material. Monitor tip 14 is, however, preferably of solid construction for strength. In the preferred embodiment, the tip of monitor tip 14 is tapered or otherwise beveled or pointed, thereby forming an angled edge that eases insertion of the production tube/monitor tip combination into a well.

Referring now to FIG. 2, the components of the downhole portion of the preferred embodiment of the present invention may be more fully described. Filter 18 is mounted within an appropriately-sized opening in monitor tip 14. Filter 18 serves to prevent dirt or other foreign material from traveling into the capillary tube. In the preferred embodiment, filter 18 fits into a cylindrically-shaped opening at the top end of monitor tip 14, and is threaded to receive fitting 22 as described below. In order to replace filter 18, the operator need merely to remove fitting 22 and then physically replace the used filter 18 with a new filter 18.

In the preferred embodiment, production tube segment orifice 17 is an opening by which gas may pass out from the interior of production tube segment 12. Directly opposite and matched to production tube segment orifice 17 is monitor tip passage 19. Monitor tip passage 19 allows gas to flow from the outside of monitor tip 14 through filter 18 and into fitting 22. By mating production tube segment orifice 17 and monitor tip passage 19 as monitor tip 14 is connected to production tube segment 12, gas may pass from within the production tube ultimately up capillary tube 24. As a result, the pressure of the gas within the production tube may be measured. More specifically, the pressure is measured within production tube segment 12 at the point where production tube segment orifice 17 intersects the wall of production tube segment 12. Preferably then, production tube segment orifice 17 should be located near, but just above, the location of the packer in the wellbore. This placement allows the best downhole pressure reading to be acquired. The size of this opening formed by production tube segment orifice 17 and monitor tip passage 19 is roughly one-fourth of an inch in diameter in the preferred embodiment, although other sizes may be employed in other embodiments.

Fitting 22 is used to connect monitor tip 14 to capillary tube 24, allowing gas that passes through filter 18 to enter capillary tube 24. In the preferred embodiment, fitting 22 connects to canister 18 using pipe threads, and connects to capillary tube 24 using a compression, flare, or other tube-type fitting. In alternative embodiments, fitting 22 may be omitted if monitor tip 14 is configured so as to connect directly to capillary tube 24. In the preferred embodiment, capillary tube 24 is a one-fourth inch diameter tube, and therefore fitting 22 should be sized for one-fourth inch tubing.

Capillary tube 24 preferably extends from fitting 22 along the entire upper length of the production tube. Banding (not shown) is preferably used to hold capillary tube 24 in place against the production tube along its length, thereby preventing damage to capillary tube 24 during insertion of the production tube and during the operational life of the well. The banding is preferably thin stainless steel, such as three-quarter inch stainless steel banding, for strength and corrosion-resistance, but other appropriate flexible and strong materials may be substituted. In the preferred embodiment, the banding is placed along capillary tube 24 roughly every sixty feet along its length.

The configuration of that portion of a preferred embodiment of the invention located at the wellhead may now be described with reference to FIG. 3. Capillary tube 24 extends upward at the wellhead and is fitted through a wing valve 26 at wellhead 25. Bull plug 27 is then fitted over capillary tube 24 and is tightened into wellhead 25. Preferably, bull plug 27 is a one-fourth inch by two inch high-pressure bull plug, intended to fit the one-fourth inch diameter capillary tube 24. Packing device 29 is then attached over the free end of capillary tube 24. Packing device 29 is preferably a one-fourth inch tube fitting to one-fourth inch pipe thread fitting. Packing device 29 is drawn over capillary tube 24 in order to seal off the pressure within capillary tube 24. Pipe fitting 31 is then connected to capillary tube 24 at its free end. Pipe fitting 31 is preferably a one-fourth inch tube fitting by one-fourth inch pipe thread fitting. Connected to pipe fitting 31 is pipe tee 33, which is preferably of the one-fourth inch high pressure type. On the vertical port of tee 33 is mounted high-pressure gauge 35, as shown in FIG. 3. On the horizontal port of tee 33 is mounted a satellite up-linked pressure monitoring device 37.

The installation and use of a preferred embodiment of the invention may now be described. CBM wells are generally lined with a casing as drilled to protect the well from collapse. The most common casing sizes are 4½ inches and 5½ inches. Since the most common production tubing sizes are 2⅜ inches and 2⅞ inches, this size disparity leaves sufficient room for the production tube to be easily inserted and removed from casing 44. The size disparity also allows additional room for capillary tube 24 to be mounted to the exterior of production tube 42, with periodic banding as described above.

Subassembly 10 is preferably fitted to the production tubing at a point just above the packer in the production string. This allows subassembly 10 to be positioned where the downhole gas pressure can be most accurately measured during operation of the well. Capillary tube 24, which is attached to and streams upward from monitoring subassembly 10, lies adjacent to the production tube up to the surface at the wellhead.

It may be noted that the tubing material that forms capillary tube 24 is preferably provided on a large roll, such that it may be fed forward as the production tube is fed into the casing. At regular intervals, preferably approximately every 60 feet or so, capillary tube 24 is fastened to production tube 42 using banding as already described. This banding operation continues until the production tube is fully inserted into the well, and is properly situated at the mineral formation of interest for gas recovery.

It may be further noted that the arrangement of capillary tube 24 and other parts described herein with respect to the preferred embodiment provides for a production tube that is free of all obstacles, allowing unrestricted outflow of gas through the production tube to the surface. This feature is particularly important for gas production in “dirty” wells such as those drilled into coal formations for CBM recovery, although the invention is not so limited. In such environments, an unusually high number of contaminants will enter the well. It will thus be necessary to periodically swab the production tube and to remove coal plugs from the production tube. With the production tube remaining otherwise open, it is a simple matter to run a swab the length of the production tube in order to clear obstacles. Otherwise, it would often be necessary to remove the production tube from the casing in order to perform maintenance. Removal of the production tube increases the equipment maintenance cost associated with the CBM extraction operation, and further causes significant downtime during CBM extraction.

Once the production tube is inserted into the casing, the capillary tube 24 material should be cut such that preferably about ten feet of excess material remains at the wellhead end of the production tube. The production tubing string should be positioned at least ten feet below the point at which the packer is to be set. The wellhead end of capillary tube 24 is then fed through wing valve 26, while picking up about five feet of the production tubing string. The production packer is then set and the normal flange-up operation at the wellhead is performed as with any gas well.

Once the production tube is in place and the packer is set, bull plug 27 is placed over capillary tube 24, and is tightened into place against the wellhead. Packing device 29 and pipe fitting 31 are then installed with respect to capillary tube 24,. whereby the gas pressure within capillary tube 24 is effectively sealed off. Pipe fitting 31 is used to attach tee 33. In the preferred embodiment, tee 31 feeds both to a mechanical pressure gauge 35 with a visual analog readout, and the satellite-linked pressure monitoring device 37.

Once all of these elements are in place, gas recovery may begin in the traditional manner. It may be seen as gas recovery proceeds, gas will pass from within the production tube into filter 18 through the passage formed by production tube segment orifice 17 and monitor tip passage 19. This gas then passes through filter 18 and passes up capillary tube 24, eventually reaching the wellhead. The pressure of this gas may be read at the wellhead visually by means of mechanical pressure gauge 35. This pressure may also be measured by satellite-linked pressure monitoring device 37, such that pressure data may be transmitted by satellite to any remote location desired. In a preferred embodiment, the pressure of many gas wells in a field, or even several different fields, may be remotely monitored in this manner. Since some algorithms for calculating gas reserves will include data concerning multiple wells operating in the same field, the ability to easy integrate this data from multiple wells serves to further increase the accuracy of gas well reserve calculations.

The present invention has been described with reference to certain preferred and alternative embodiments that are intended to be exemplary only and not limiting to the full scope of the present invention as set forth in the appended claims.