Patent Application
20240426192
The present invention relates generally to apparatus and methods for conditioning well fluid. More particularly, the present invention relates to a downhole tool for conditioning well fluid extracted from an underground hydrocarbon reservoir to prevent paraffin deposits in well tubing. Additionally, the present invention relates to a dewatering tool for conditioning well fluid extracted from an underground hydrocarbon reservoir to improve dewatering of well fluid aboveground.
As is well known, oil, which is a complex mixture of hydrocarbons, is extracted from underground reservoirs using various methods. The methods used in any given case depend on several factors. One such factor is the geology of the formation containing the underground reservoir, and another factor is the properties of the contents of the underground reservoir.
Conventional oil, which is also known as crude oil or petroleum, is an organic compound that has developed naturally within the Earth's crust. It is a hydrocarbon, meaning that it is composed primarily of hydrogen and carbon, but often contains traces of other elements, such as nitrogen, sulfur and various metals.
Conventional oil is extracted using traditional drilling and pumping methods. In brief, a wellbore is drilled from the surface to an underground hydrocarbon reservoir located deep under the surface, and lined with casing. Well tubing is suspended into the casing to connect various surface equipment to the underground hydrocarbon reservoir. Conventional oil is a liquid at atmospheric temperature and pressure, allowing it to be pumped to the surface through the well tubing. In addition to conventional oil, an underground hydrocarbon reservoir may also contain hydrocarbon gases, and water, which may also be brought up to the surface through the well tubing mixed together into one well fluid.
Conventional oil typically consists of four constituent parts, namely oil, resin, asphaltene, and preasphaltene (i.e. carbon and carboid). The chemical and physical properties of conventional oil depend significantly on the relative amounts of each constituent and their properties. The asphaltenes usually contain more condensed aromatic compounds than do the resin and oil constituents. The resins contain aromatic or naphthenic hydrocarbons, and components of oil constituents may have naphthenic or paraffin structures. Asphaltenes and preasphaltenes in their natural state exist in micelle form, peptized with resin molecules.
As mentioned above, conventional oil is typically extracted by pumping well fluid from deep underground hydrocarbon reservoirs up to the earth's surface with various surface equipment and well tubing. The movement of the well fluid from deep underground to the surface subjects the well fluid to changes in pressure and temperature as it flows towards the surface through the well tubing. These pressure and temperature changes affect the oil constituents, including the interfacial tension between the various phases of the oil, for example.
The changes in pressure and temperature acting on the mobilized well fluid is particularly problematic in oil extraction because they tend to cause the paraffin and asphaltene constituents of conventional oil to nucleate and precipitate out of the well fluid to form deposits on well tubing and surface equipment. The formation of paraffin and asphaltene deposits on the inner walls of well tubing reduces the rate of oil extraction over time. The flow of well fluid through the well tubing gradually decreases as the paraffin and asphaltene deposits build up on the inner wall of the well tubing, and reduce the cross-sectional area of the well tubing. This process can result in complete blockage of the well tubing if left unchecked.
Prior attempts for addressing problems caused by precipitation and buildup of paraffin, asphaltene, and other hydrocarbons on the inner wall of well tubing include using magnets, chemicals, and heat. For example, heating the oil in the reservoir, or the well tubing has been shown to increase the solubility of paraffin to allow the well fluid to be extracted without paraffin deposits forming on the inner wall of the well tubing. As another example, the well fluid may be treated with dispersants or crystal modifiers to slow down the rate of precipitation of paraffins and asphaltenes, thereby reducing the buildup of paraffin and asphaltene deposits on the inner wall of well tubing. As yet another example, surfactants may be injected into the well fluid to decrease the interfacial tension in the oil. As yet another example, solvents may be used to thin and dissolve the paraffin and asphaltene deposits. As yet another example, the buildup may be physically removed by scraping the inner wall of the well tubing. Unfortunately, each of the above prior attempts have certain disadvantages relating to effectiveness, equipment cost, material cost, labor cost, and/or down time cost.
U.S. Pat. App. Pub. No. 2019/0224586 Krummel discloses an attempt to use various patterns of low energy to modify constituents and phases of oil to increase both the oil's flow and recovery. In this regard, Krummel discloses a band-pass filter which is molded to form a part that fits snugly around a pipe used for oil transport. According to Krummel passive energy supplied by underground heat is transmitted through the casing to the band-pass filter, where a resultant spectral energy pattern from the band-pass filter passes through the pipe and into the oil. Krummel also mentions that the band-pass filter can include one or more passages for the oil to move through, and can be deployed as a sieve or filter that allows for energy transmission into the oil.
Additionally, Para Service International Inc. (Calgary, Alberta, Canada) has developed a downhole tool sold under the trademark Enercat™. The Enercat™ downhole tool is cast from aluminum and looks like a standard production-tubing pup joint. The Enercat™ downhole tool comprises a tube with a cylindrical bore, and a jacket surrounding the tube. The jacket contains quartz crystals and semi-precious metals. The Enercat™ tool is described as being useful for preventing paraffin from turning into solid form, and allowing crude oil and water particles to move smoothly and cleanly through the pipe without causing deposition problems.
The Enercat™ downhole tool is also described as being useful for eliminating scale deposition to give increased equipment life and efficiency. A problem with the Enercat™ downhole tool is that it is not effective in treating oil with a low water content, or oil with a high gas content.
Merus GmbH (Sindelfingen, Germany) makes a product for treating fluids, mainly water to get rid of limescale, corrosion or biofouling in pipes. The product is called a Merus Ring which is configured for installation around a pipe. The Merus Ring is described as being made of aluminum, and treated with a special process. Once placed around a water pipe, the Merus Ring is said to transmit its active oscillation to the water flowing inside the pipe, which increases the solubility of the soluble parts in water flowing in the pipe surrounded by the Merus Ring.
Other prior attempts at conditioning oil and water to reduce precipitation and buildup of deposits on pipes are disclosed in U.S. Pat. App. Pub. No. 2019/0152808, U.S. Pat. No. 7,972,390, and Khadijeh Barati, et al. “Molecular Oscillation Technology: New Phenomenon to Reduce Emitter Clogging in Trickle Irrigation”, (2014) J. Irrig. Drain. Eng., 140 (11): 04014034-1 to 04014034-8.
Well fluid extracted from underground hydrocarbon reservoirs often contain water. The water needs to be removed to have a vendable product. The removal of water from the well fluid is called “dewatering”. Dewatering typically involves one or more of the following processes:
To be vendable, the water content of the well fluid needs to be reduced to less than 1%. However, dewatering typically requires a large amount of energy, and is costly.
However, there is a continuing need for improvement in methods for reducing the precipitation and buildup of paraffin, asphaltene, and other hydrocarbon deposits on the inner wall of well tubing during oil extraction.
What is desired is an apparatus that overcomes at least some of the problems associated with the prior art.
In one aspect, the present invention is directed to a downhole tool which is configured for attachment to well tubing. The downhole tool contains a plurality of well fluid contacting structures which define a meandering, non-linear path for well fluid to pass through, as the well fluid is extracted through the well tubing. The well fluid contacting structures, which are metal nuggets or spheres according to a preferred embodiment of the invention, are contained within the downhole tool between a pair of spaced apart screens, with openings sized and shaped to allow the well fluid to pass therethrough, but not the spheres.
Advantageously, the downhole tool has been found to be effective in reducing the buildup of paraffin and asphaltene deposits on the inner wall of well tubing during extraction of well fluid, including well fluid comprising oil with a low, or no water content, and well fluid comprising oil with a high gas content.
Therefore, in accordance with one aspect of the present invention, there is disclosed a downhole tool adapted to be connected to well tubing for extracting well fluid from an underground hydrocarbon reservoir, said downhole tool comprising:
In accordance with another aspect of the present invention, there is disclosed a method of conditioning well fluid from an underground hydrocarbon reservoir being extracted through well tubing, said method comprising the steps of:
In a second aspect, the present invention is directed to a dewatering tool which is configured for attachment to a flow line upstream of an oil/water separator. The dewatering tool contains a plurality of well fluid contacting structures which define a meandering, non-linear path for well fluid to pass through, as the well fluid is forced therethrough on its path to the oil/water separator. The well fluid contacting structures, which are metal nuggets or spheres according to a preferred embodiment of the invention, are contained within the dewatering tool between a pair of spaced apart screens, with openings sized and shaped to allow the well fluid to pass therethrough, but not the spheres.
Advantageously, the dewatering tool has been found to be effective in improving the dewatering of well fluid.
Therefore, in accordance with another aspect of the present invention, there is disclosed a dewatering tool adapted to be connected to a flow path for well fluid from an underground hydrocarbon reservoir to an oil/water separator, said dewatering tool comprising:
In accordance with another aspect of the present invention, there is disclosed a method of dewatering well fluid from an underground hydrocarbon reservoir, said method comprising the steps of:
Reference will now be made to the preferred embodiments of the present invention with reference, by way of example only, to the following drawings in which:
The present invention is described in more detail with reference to exemplary embodiments thereof as shown in the appended drawings. While the present invention is described below including preferred embodiments, it should be understood that the present invention is not limited thereto. Those of ordinary skill in the art having access to the teachings herein will recognize additional implementations, modifications, and embodiments which are within the scope of the present invention as disclosed and claimed herein. In the figures, like elements are given like reference numbers. For the purposes of clarity, not every component is labelled in every figure, nor is every component of each embodiment of the invention shown where illustration is not necessary to allow those of ordinary skill in the art to understand the invention.
The downhole tool 10 has a tubular mandrel 20 with first and second connector ends 22,24. The tubular mandrel 20 defines a mandrel bore 26. The first and second connector ends 22,24 are adapted for connecting the tubular mandrel 20 with, and disconnecting the tubular mandrel 20 from the well tubing 12. Preferably, the tubular mandrel 20 may be made from a variety of metals, including, steel, stainless steel, copper, brass, bronze, or the like. What is desired is that the tubular mandrel 20 be sufficiently strong and durable to resist loads and deformations associated with production and repeated workovers.
As can be seen, the preferred downhole tool 10 is sized and shaped to resemble a pup joint. Indeed, as discussed below in Example 1, the downhole tool 10 may be made from a pup joint. Similar to a pup joint, first and second connector ends 22,24 preferably have external upset end (EUE) 8 round threads to facilitate connecting the downhole tool 10 with, and disconnecting the downhole tool 10 from well tubing 12. The first and second connector ends 22,24 may be provided with other types of connectors known in the art, such as, for example non-upset end (NUE). What is important is that the downhole tool 10 may be connected with, and disconnected from well tubing 12. All such embodiments are comprehended by the present invention.
Well tubing 12 comes in many different shapes and sizes, including different lengths and outside diameters. Well tubing 12 is sized to support the expected rates of extraction of oil and gas at a well. Different extraction rates require different sizes of well tubing 12. Typically, however, well tubing 12 has an outside diameter in the range of 2⅜ inches to 4.5 inches. Since the downhole tool 10 is preferably adapted to be connected with and disconnected from well tubing, it will typically be provided with a diameter to match the outside diameter of the well tubing to which it is intended to connect with. For this reason, a preferred downhole tool 10 may have an outside diameter in the range of 2⅜ inches to 4.5 inches, depending on the application. That said, the downhole tool 10 may have a smaller, or larger outside diameter depending on the well tubing 12 it is intended to be connected with, and the required flow rate through the downhole tool 10 itself, as will be appreciated by persons skilled in the art. All such embodiments are comprehended by the present invention.
Preferably the downhole tool 10 may be adapted for connecting at any point in the oil well tubing string 18, which is deemed optimal for conditioning the well fluid 14. Preferably, the downhole tool 10 may be attached to well tubing 12 at the bottom of the oil well tubing string 18, as shown in
A plurality of well fluid contacting structures 42 are contained within the mandrel bore 26 between the first and second connector ends 22,24, using a pair of screens 44. As can be seen, the screens 44 are positioned within the mandrel bore 26, between the first and second connector ends 22,24. Preferably, the screens 44 are welded in position within the mandrel bore 26. However, the screens 44 may be secured in position within the mandrel bore 26 by any other means, including for example using threaded fasteners, pins, snap rings, threaded rings, and the like.
Furthermore, although the screens 44 are preferably permanently attached to the mandrel bore 26, it is contemplated that in at least some embodiments, one or both screens 44 may be releasably attached to the mandrel bore 26, to permit access to the well fluid contacting structures 42. For example, the screens 44 may be threadingly secured to matching threaded portions within the mandrel bore 26. As another example, separate threaded rings (not shown), or snap rings (not shown) may be used to clamp the screens 44 in position against respective annular shoulders (not shown) positioned within the mandrel bore 26. All such embodiments are comprehended by the present invention.
As best seen in
Preferably, the size and number of openings 46 will be selected to provide the largest possible cross-sectional area for the well fluid 14 to pass through, in order to maintain an adequate flow rate of the well fluid 14 through the downhole tool 10, while containing the well fluid contacting structures 42 within the mandrel bore 26, and without compromising the structural integrity of the screens 44.
The screens 44 are spaced apart within the mandrel bore 26 to define a well fluid conditioning portion 48. Within the well fluid conditioning portion 48, the fluid contacting structures 42 form meandering, non-linear paths 50 for the well fluid 14 to pass from the first connector end 22 to the second connector end 24. The non-linear paths 50 are formed between the spaces of the fluid contacting structures 42.
As will be described in more detail below, what is desired is to increase the amount, and duration of contact of the well fluid 14 with the surfaces of the well fluid contacting structures 42. Preferably, this may be achieved by positioning the well fluid contacting structures 42 in the mandrel bore 26, and forcing the well fluid 14 to follow non-linear paths 50 through the spaces formed between the well fluid contacting structures 42.
Without being bound to a particular theory, it is believed that the atomic vibrations of the fluid contacting structures 42 affect the physical bonds between oil molecules in the well fluid 14 as the well fluid 14 contacts the fluid contacting structures 42, and flows along the non-linear paths 50 between the well fluid contacting structures 42. Specifically, the atomic vibrations of the fluid contacting structures 42 are believed to increase the atomic vibrations in the oil molecules in the well fluid, to counter the decrease in atomic vibrations experienced by the oil molecules as they are pumped up the well tubing 12 from the underground hydrocarbon reservoir 16. According to this theory, the decrease in atomic vibrations of the oil molecules as they are pumped up the well tubing 12 increases the London dispersion intermolecular forces acting between the oil molecules, causing paraffin, asphaltene, and other hydrocarbon molecules to pull together and precipitate out of the well fluid 14, forming hydrocarbon deposits on the well tubing 12. However, conditioning the well fluid 14 by subjecting it to the atomic vibrations of the fluid contacting structures 42 increases the atomic vibrations of the oil molecules to weaken the London dispersion intermolecular forces acting between the oil molecules enough to prevent their precipitation out of the well fluid 14, thereby preventing, or at least reducing the formation of hydrocarbon deposits on the well tubing 12.
While there is no upper limit to the possible length of the preferred downhole tool 10, since the well fluid conditioning portion 48 is provided within the mandrel bore 26, the lower limit of the length of the downhole tool 10 will be governed by the desired length of the conditioning portion 48. In other words, the length of the downhole tool 10 cannot be less than the length of the conditioning portion 48. That said, it is contemplated that the length of downhole tools 10 may be in a range of 6 inches to 4 feet, depending on the particular application.
Preferably, the well fluid conditioning portion 48 may be sized based on the expected maximum extraction rate of well fluid 14 at a well. In this regard, good results have been obtained by calculating a desired volume for the well fluid conditioning portion 48 using a ratio of about 2.0096 inch2 (i.e. 0.03293 liters) of desired volume for every one barrel of fluid per day (BPD) expected maximum extraction rate at the well.
By way of example, the preferred volume of the well fluid conditioning portion 48 in a tubular mandrel 20 having a 1 inch inside diameter, for use in a well having an expected maximum extraction rate (EMER) of 10 BPD, would be at least 0.329 liters (i.e. 20.10 inch3), which correlates to a distance D between screens 44 of about 25.59 inches, according to the below formula:
Extending the example further, the preferred volume of the well fluid conditioning portion 48 in a tubular mandrel 20 having a 1 inch inside diameter, for use in a well having a maximum expected maximum extraction rate (EMER) of 25 BFD would be 0.823 liters (i.e. 50.24 inch3), which correlates to a distance D between screens 44 of about 63.97 inches.
By way of further example, the preferred volume of the well fluid conditioning portion 48 in a tubular mandrel 20 having a 2.44 inch inside diameter, for use in a well having an expected maximum extraction rate (EMER) of 100 BFD would be 3.293 liters (i.e. 200.96 inch3), which correlates to a distance D between screens 44 of about 42.98 inches.
That said, it is contemplated that the downhole tool 10 may be provided with a well fluid conditioning portion 48 having a smaller, or a larger volume than one calculated using the formula mentioned above, depending on the application. It will be appreciated that providing the well fluid conditioning portion 48 with a larger volume, allows an increased number of well fluid contacting structures 42 to be used, thereby increasing the amount of contact between the well fluid 14 and the fluid contacting structures 42. While it is believed that increasing the amount of contact between the well fluid 14 and the fluid contacting structures 42 may be beneficial, the benefit comes with a greater material, and manufacturing cost. On the other hand, providing the well fluid conditioning portion 48 with a smaller volume, although not ideal, may still provide adequate results for certain applications.
As mentioned above, the well fluid conditioning portion 48 of the tubular mandrel 20 is preferably filled with a plurality of well fluid contacting structures 42. Preferably, the well fluid contacting structures 42 may be made from metal and formed into nuggets or spheres. Good results have been obtained using metal spheres comprising copper, including 99.99% pure copper spheres, and brass (a copper alloy comprising about 60% copper with the remainder being substantially zinc). Other copper alloys are also expected to be suitable, including bronze, for example, which is a copper alloy comprising about 78% copper with the remainder being substantially tin. However, it is contemplated that the well fluid contacting structures 42 may be made from other metals, such as for example, silver and gold, which are in the same group as copper in the periodic table (group 11). Though the high cost of silver and gold may make their use unfeasible in some applications.
That said, all metals are expected to yield satisfactory results, provided that they can be formed into nuggets or spheres, as mentioned above, and are sufficiently durable to withstand the conditions they will experience in the underground hydrocarbon reservoir 16. Additionally, the preferred metals are made of chemical elements having an abundance of electrons (the more electrons the better), and be cost effective to obtain, and incorporate into the downhole tool 10. Preferably, the metals may be made of chemical elements having at least thirteen electrons (i.e. aluminum). Most preferably, the metals may be made of chemical elements having at least twenty-nine electrons (i.e. copper).
Furthermore, combinations of two or more different metal nuggets and/or spheres may be disposed in the well fluid conditioning portion 48. For example, the well fluid conditioning portion 48 may be filled with half copper spheres, and half with aluminum spheres. Of course, other ratios may be used.
Although the spheres may be hollow, solid spheres are preferred because, it is believed, the greater mass of the solid spheres yields better results. It is believed that providing the well fluid contacting structures 42 with rounded surfaces will assist the flow of well fluid 14 through the non-linear paths 50 they define in the well fluid conditioning portion 48 of the tubular mandrel 20. Good results have been obtained using spheres having a diameter of ½ inch or 1 inch. However, it is contemplated that spheres with other diameters may be used. Preferably, the other diameter may be in a range of about ½ inch to about 7 inches, or more. What is important is that the size and shape of the fluid contacting structures 42 is selected to form non-linear paths 50 in the well fluid conditioning portion 48, to maintain a desired rate of flow of the well fluid 14 through the downhole tool 10.
In general, a downhole tool 10 with a specific inside diameter can be made to provide one of a wide range of rates of flow. The desired rate of flow may preferably be achieved by increasing or decreasing the size of the well fluid contacting structures 42 inside of the well fluid conditioning portion 48, and/or by changing the number or size of openings 46 in screens 44.
The desired rate of flow may be defined as a minimum rate of flow of well fluid 14 through the downhole tool 10. For example, it may be a requirement of an oil well operator that the downhole tool 10 does not restrict the extraction of well fluid 14 from the underground hydrocarbon reservoir 16, in which case the downhole tool 10 may be made and tested to ensure that the rate of flow through the downhole tool 10 is at least greater than the actual, or expected extraction rate the oil well is capable of satisfying. The maximum rate of flow through a given downhole tool 10 can be determined by a flow test, measuring pumping pressure at different rates of flow, up to a value equivalent to, for example, 4000 BPD. The maximum rate of flow is reached when the pumping pressure indicates a restriction.
Alternately, the desired rate of flow may be defined as a maximum rate of well fluid 14 through the downhole tool 10. For example, it may be preferable to maintain a minimum duration of time the well fluid 14 is in contact with the well fluid contacting structures 42.
Clearly, the above considerations are diametrically opposed to one another, and it may be necessary in some instances to settle on a compromise between the two.
Preferably, the downhole tool 10 may be configured to provide a rate of flow through the downhole tool 10 that allows the well fluid 14 to remain in the well fluid conditioning portion 48 to contact the fluid contacting structures 42 for as long as possible. In other words, the slower the rate of flow through the downhole tool 10 the better. Without being limiting, a preferred rate of flow is less than about 210 feet per hour for a downhole tool 10 with a 1.5 foot long well fluid conditioning portion 48, for example. If the rate of flow is greater than 210 feet per hour, a second downhole tool 10 may be added in series. Preferably, the well fluid conditioning portion 48 may be sized so that the well fluid 14 will remain therein for at least 30 seconds as it passes through the downhole tool 10 at the desired rate of flow.
Furthermore, the metal spheres disposed in the well fluid conditioning portion 48 may be provided with two or more different diameters. For example, the well fluid conditioning portion 48 may be filled with half copper spheres having ½ inch diameters, and half with 1 inch diameters. Of course, other ratios and diameters may be used. All such embodiments are comprehended by the present invention.
Advantageously, the well fluid contacting structures 42 may be pre-treated to enhance the effect of the well fluid contacting structures 42, or to impart other characteristics on the well fluid 14. For example, it has been found that the formation of hydrocarbon depositions in well tubing 12 may be reduced further by pre-treating the well fluid contacting structures 42 by tuning them using an Enercat™ E1000 (2430946 Alberta Ltd., Calgary, Alberta, Canada) for a period of 24 hours.
Referring now to
A plurality of well fluid contacting structures 42 are contained within the mandrel bore 26 between the first and second connector ends 22,24, using a pair of screens 44. As can be seen, the screens 44 are positioned within the mandrel bore 26, between the first and second connector ends 22,24. Preferably, the screens 44 are welded in position within the mandrel bore 26, about 3 inches from the respective first and second connector ends 22,24, defining a well fluid conditioning portion 48 therebetween. However, the screens 44 may be secured in position within the mandrel bore 26 by any other means, including for example using threaded fasteners, pins, snap rings, threaded rings, and the like. It is also contemplated that the screens 44 may be provided with threads about their circumference, to allow them to be threadingly secured inside the mandrel bore 26 via matching threaded portions inside the mandrel bore 26.
As discussed above, the well fluid contacting structures 42 may be pre-treated to enhance the effect of the well fluid contacting structures 42, or to impart other characteristics on the well fluid 14.
The first connector end 22 of the tubular mandrel 20 is a male connector in this example, and a fish neck assembly 52 is threadingly attached to the first connector end 22 by a matching female connector. The second connector end 24 is a female connector in this example, and a seating assembly 54 is threadingly attached to the second connector end 24 by a matching male connector. The fish neck assembly 52 may be used to install and retrieve the downhole tool 10 with the use of a wireline or slickline truck, in a known manner. The seating assembly 54 is adapted to land in a pump seating nipple (not shown) inside the well tubing 12 and hold the downhole tool 10 securely in place close to the bottom of the oil well tubing string 18.
By way of example, the tubular mandrel 20 may be a four foot long stainless steel tube having an outside diameter of 1¾ inches, and an inside diameter of 1½ inches, and the well fluid contacting structures 42 may be 1 inch copper spheres.
By way of further example, the tubular mandrel 20 may be a four foot long stainless steel tube having an outside diameter of 2¼ inches, and an inside diameter of 2 inches, and the well fluid contacting structures 42 may be 1 inch copper spheres.
However, it will be appreciated that the tubular mandrel 20 may be made from other materials, and in other lengths and diameters, depending on the application. Similarly, the well fluid contacting structures 42 may be made from other materials, and in other diameters, as discussed above. All such embodiments are comprehended by the present invention.
The downhole tool 10 will now be further elaborated using the following non-limiting examples, which yielded good results.
A two foot long downhole tool 10 was made by the following steps.
A conventional two foot long tubing pup joint made of L80 grade steel was obtained (Baron Oilfield Supply, Calgary, AB, Canada). The pup joint had an outside diameter of 2.88 inches, an inside diameter of 2.44 inches, and EUE 8 round threads on each end.
A pair of 2.44 inch diameter screens 44 were fabricated by plasma cutting 2.44 inch discs from a ⅛ inch (11 gage) thick steel (304SS) plate, and drilling sixteen, ⅛ inch round holes into each disk to form the openings 46.
One of the pair of 2.44 inch diameter screens 44 was welded within the pup joint bore 26, three inches from one end of the pup joint.
Next, the pup joint bore 26 was filled with fifty-five solid, 1 inch diameter 99.99% copper spheres (RotoMetals, Inc., San Leandro, CA, U.S.A.). The copper spheres were pre-treated by tuning them in an Enercat™ E1000 for a period of 24 hours, prior to being used to fill the pup joint bore 26.
After filling the pup joint bore 26 with the pre-treated copper spheres, the second of the pair of 2.44 inch screens 44 was welded within the pup joint bore 26, three inches from the other end of the pup joint.
In this example, the pair of screens 44 were spaced apart a distance of 18 inches (i.e. about 1 foot and 6 inches), defining a conditioning portion 48 having a volume of about 1.370 liters (83.58 inch3). The distance was calculated according to the formula discussed above, based on an expected maximum extraction rate of 41.59 BPD.
The downhole tool 10 was installed in a gas lift well 28 that had been operating continuously for at least 10 years prior. A gas lift well 28 uses natural gas injected into the well casing to lift the well fluid 14 to the surface through the well tubing 12. Prior to installation of the downhole tool 10, the well operator reported buildups of paraffin deposits in the upper portions of the well tubing 12 requiring a weekly maintenance schedule to remove the paraffin deposits from the well tubing 12. Routine cleaning utilized wax knives to scrape the inside of the well tubing free of paraffin.
The downhole tool 10 was installed at the bottom of the well tubing 12, attached to a tail joint, extending into an underground hydrocarbon reservoir 16 comprising oil, gas, and water, located about 5,000 feet below the surface 34. Prior to installation, the well tubing 12 was cleaned out to remove paraffin deposits that had built up in the well tubing 12 since the previous cleaning.
After the installation of the downhole tool 10, the gas lift well 28 was operated normally, producing on average 34 BPD of well fluid 14, with the exception that the regularly scheduled well tubing clean outs were discontinued for the duration of the experiment.
Thirty-five days after the downhole tool 10 was installed in the well tubing 12, an inspection of the well tubing 12 was performed, which revealed an absence of paraffin and asphaltene deposits in the well tubing 12.
A follow up with the well operator four months after installation of the downhole tool 10 revealed that the gas lift well 28 had continued to operate without needing to clean out the well tubing 12. Based on this result, it was inferred that the downhole tool 10 successfully maintained the well tubing 12 free of paraffin and asphaltene deposits, allowing the well operator to continue to operate the gas lift well 28 without needing to reinstate the previously required weekly maintenance schedule to clean out the well tubing 12.
Additionally, before and after samples of well fluid 14 were sent to Oilfield Labs of America (Dallas, Texas) for analysis. The results showed that in this example, the downhole tool 10 lowered cloud point of the oil extracted from the gas lift well 28 from 22° C. to 20° C., and increased its API gravity from 36.8 to 37.
A two foot long downhole tool 10 was made as described in the above Example 1.
The downhole tool 10 was installed in a walking beam pump well 66 that had been operating continuously for at least 5 years. A walking beam pump 74 utilizes a sucker rod pumping system to artificially lift well fluid 14 from the underground hydrocarbon reservoir to the surface. The well fluid 14 extracted from the underground hydrocarbon reservoir was substantially free of water and gas.
Prior to installation of the downhole tool 10, the well operator reported that the rate of oil extraction averaged about 3 to 5 BPD. Buildups of paraffin deposits in the upper portions of the well tubing 12 required a thirty-day maintenance schedule to remove the paraffin deposits from the well tubing 12, which would otherwise plug the well tubing 12 and stop oil extraction. The thirty-day maintenance schedule was required, despite the well operator using paraffin prevention chemicals during operation of the well.
The downhole tool 10 was installed at the bottom of the well tubing 12, attached to a tail joint, extending into an underground hydrocarbon reservoir comprising oil substantially free of water and gas. The underground hydrocarbon reservoir was located about 5,000 feet below the surface. Prior to installation, the well tubing 12 was cleaned out to remove paraffin deposits that had built up in the well tubing 12 since the previous cleaning. The well tubing 12 was cleaned out by circulating hot oil through the well tubing 12.
After the installation of the downhole tool 10, the walking beam pump well 66 was operated normally, but without paraffin prevention chemicals, and the regularly scheduled well tubing clean outs were discontinued for the duration of the experiment. With the downhole tool 10 installed, the well produced on average 7 to 8 BPD of well fluid 14 (i.e. an increase of 3 to 4 BPD in the extraction rate).
A follow up with the well operator seven months after installation of the downhole tool 10 revealed that the walking beam pump well 66 had continued to operate without needing to clean out the well tubing or use paraffin prevention chemicals.
Based on this result, it was inferred that the downhole tool 10 successfully maintained the well tubing 12 free of paraffin and asphaltene deposits, allowing the well operator to continue to operate the walking beam pump well 66 without needing to reinstate the previously required use of paraffin prevention chemicals, and thirty-day maintenance schedule to clean out the well tubing 12.
Referring now to
When installed in the flow line 62 upstream of the oil/water separator 64, the dewatering tool 60 has been found to reduce the water content in the oil phase 70 of well fluid 14 in the oil/water separator 64 to less than 1%. As will be appreciated, a reduction in the water content of the oil product is desirable for the well operator, as meeting this threshold is a requirement of the well operator's customers.
Referring back to
In this example, the tubular mandrel 20 is a stainless steel tube, with NPT threads formed in each end 22,24 for connecting the dewatering tool 60, and disconnecting the dewatering tool 60 from the flow line 62. The first and second connector ends 22,24 may be provided with other types of connectors known in the art, such as, for example non-upset end (NUE). It is also contemplated that the first and second connector ends 22,24 may be provided without threads or the like, for example to allow the dewatering tool 60 to be connected to the flow line 62 by other known means, including welding, for example. What is important is that the dewatering tool 60 may be connected to the flow line 62 upstream of the oil/water separator 64, so that the well fluid 14 will pass through the dewatering tool 60 before reaching the oil/water separator 64. All such embodiments are comprehended by the present invention.
As will be appreciated, flow lines 62 come in many different sizes. Flow lines 62 are sized to support the expected rates of extraction of well fluid 14 at a well. Different extraction rates require different sizes of flow lines 62. Typically, however, a flow line 62 will have an outside diameter in the range of 1 inch to 4.5 inches. Since the dewatering tool 60 is preferably adapted to be connected to a flow line 62, it will typically be provided with an outside diameter to match the outside diameter of the flow line 62 to which it is intended to connect to. For this reason, a preferred dewatering tool 60 may have an outside diameter in the range of 1 inch to 4.5 inches, depending on the application. That said, the dewatering tool 60 may have a smaller, or larger outside diameter depending on the flow line 62 it is intended to be connected to, and the required flow rate through the dewatering tool 60 itself, as will be appreciated by persons skilled in the art. All such embodiments are comprehended by the present invention.
A plurality of well fluid contacting structures 42 are contained within the mandrel bore 26 between the first and second connector ends 22,24, using a pair of screens 44. As can be seen, the screens 44 are positioned within the mandrel bore 26, between the first and second connector ends 22,24. Preferably, the screens 44 are welded in position within the mandrel bore 26. However, the screens 44 may be secured in position within the mandrel bore 26 by any other means, including for example using threaded fasteners, pins, snap rings, threaded rings, and the like.
Furthermore, although the screens 44 are preferably permanently attached to the mandrel bore 26, it is contemplated that in at least some embodiments, one or both screens 44 may be releasably attached to the mandrel bore 26, to permit access to the well fluid contacting structures 42. For example, the screens 44 may be threadingly secured to matching threaded portions within the mandrel bore 26.
As another example, separate threaded rings (not shown), or snap rings (not shown) may be used to clamp the screens 44 in position against respective annular shoulders (not shown) positioned within the mandrel bore 26. All such embodiments are comprehended by the present invention.
As best seen in
Preferably, the size and number of openings 46 will be selected to provide the largest possible cross-sectional area for the well fluid 14 to pass through, in order to maintain an adequate flow rate of the well fluid 14 through the dewatering tool 60, while containing the well fluid contacting structures 42 within the mandrel bore 26, and without compromising the structural integrity of the screens 44.
The screens 44 are spaced apart within the mandrel bore 26 to define a well fluid conditioning portion 48. Within the well fluid conditioning portion 48, the fluid contacting structures 42 form meandering, non-linear paths 50 for the well fluid 14 to pass from the first connector end 22 to the second connector end 24. The non-linear paths 50 are formed between the spaces of the well fluid contacting structures 42.
As explained above in connection to the dewatering tool 60, what is desired is to increase the amount, and duration of contact of the well fluid 14 with the surfaces of the well fluid contacting structures 42. Preferably, this may be achieved by positioning the well fluid contacting structures 42 in the mandrel bore 26, and forcing the well fluid 14 to follow non-linear paths 50 through the spaces formed between the well fluid contacting structures 42.
Without being bound to a particular theory, it is believed that the atomic vibrations of the well fluid contacting structures 42 affect the physical bonds between oil molecules in the well fluid 14 as the well fluid 14 contacts the well fluid contacting structures 42, and flows along the non-linear paths 50 between the well fluid contacting structures 42. Specifically, the atomic vibrations of the well fluid contacting structures 42 are believed to increase the atomic vibrations in the oil and water molecules in the well fluid 14. According to this theory, conditioning the well fluid 14 by subjecting it to the atomic vibrations of the well fluid contacting structures 42 increases the atomic vibrations of the oil and water molecules to weaken the London dispersion intermolecular forces acting between the oil and water molecules enough to increase the rate of their separation in to an oil phase 70 and a water phase 72, thereby facilitating the dewatering process carried out in the oil/water separator 64.
While there is no upper limit to the possible length of the preferred dewatering tool 60, since the well fluid conditioning portion 48 is provided within the mandrel bore 26, the lower limit of the length of the dewatering tool 60 will be governed by the desired length of the well fluid conditioning portion 48. In other words, the length of the dewatering tool 60 cannot be less than the length of the well fluid conditioning portion 48. That said, it is contemplated that the length of dewatering tools 60 may be in a range of 6 inches to 4 feet, depending on the particular application.
Preferably, the well fluid conditioning portion 48 of the dewatering tool 60 may be sized based on the expected maximum extraction rate of well fluid 14 at a well, as discussed above in relation to the downhole tool 10. For example, the size of the well fluid conditioning portion 48 may be obtained by calculating a desired volume for the well fluid conditioning portion 48 using a ratio of about 2.0096 inch2 (i.e. 0.03293 liters) of desired volume for every one barrel of fluid per day (BPD) expected maximum extraction rate at the well. However, it is contemplated that the dewatering tool 60 may be provided with a well fluid conditioning portion 48 having a smaller, or a larger volume than one calculated using the formula mentioned above, depending on the application.
As mentioned above, the well fluid conditioning portion 48 of the tubular mandrel 20 is preferably filled with a plurality of well fluid contacting structures 42. Preferably, the well fluid contacting structures 42 may be made from metal and formed into nuggets or spheres. Good results have been obtained using metal spheres comprising copper, including brass (a copper alloy comprising about 60% copper with the remainder being substantially zinc). Other copper alloys are also expected to be suitable, including bronze, for example, which is a copper alloy comprising about 78% copper with the remainder being substantially tin. However, it is contemplated that the well fluid contacting structures 42 may be made from other metals, such as for example, silver and gold, which are in the same group as copper in the periodic table (group 11). Though the high cost of silver and gold may make their use unfeasible in some applications.
That said, all metals are expected to yield satisfactory results, provided that they can be formed into nuggets or spheres, as mentioned above, and are sufficiently durable to withstand the conditions they will experience in the underground hydrocarbon reservoir 16. Additionally, the preferred metals are made of chemical elements having an abundance of electrons (the more electrons the better), and be cost effective to obtain, and incorporate into the dewatering tool 60. Preferably, the metals may be made of chemical elements having at least thirteen electrons (i.e. aluminum). Most preferably, the metals may be made of chemical elements having at least twenty-nine electrons (i.e. copper). Furthermore, combinations of two or more different metal nuggets and/or spheres may be disposed in the well fluid conditioning portion 48. For example, the well fluid conditioning portion 48 may be filled with half copper spheres, and half with aluminum spheres. Of course, other ratios may be used.
Again, although the spheres may be hollow, solid spheres are preferred because, it is believed, the greater mass of the solid spheres yields better results. It is believed that providing the well fluid contacting structures 42 with rounded surfaces will assist the flow of well fluid 14 through the non-linear paths 50 they define in the well fluid conditioning portion 48 of the tubular mandrel 20. Good results have been obtained using spheres having a diameter of ½ inch. However, it is contemplated that spheres with other diameters may be used. Preferably, the other diameter may be in a range of about ½ inch to about 7 inches, or more. What is important is that the size and shape of the well fluid contacting structures 42 is selected to form non-linear paths 50 in the well fluid conditioning portion 48, to maintain a desired rate of flow of the well fluid 14 through the dewatering tool 60.
As in the case of the above described downhole tool 10, the dewatering tool 60 with a specific inside diameter may also be made to provide one of a wide range of rates of flow. And similarly, the desired rate of flow may preferably be achieved by increasing or decreasing the size of the well fluid contacting structures 42 inside of the well fluid conditioning portion 48, and/or by changing the number or size of openings 46 in screens 44.
Bearing in mind the above described considerations regarding desired rate of flow, the dewatering tool 60, may preferably be configured to provide a rate of flow therethrough that allows the well fluid 14 to remain in the well fluid conditioning portion 48 to contact the well fluid contacting structures 42 for as long as possible.
In other words, the slower the rate of flow through the dewatering tool 60 the better. Without being limiting, a preferred rate of flow is less than about 210 feet per hour for a dewatering tool 60 with a 1.5 foot long well fluid conditioning portion 48, for example. If the rate of flow is greater than 210 feet per hour, a second dewatering tool 60 may be added in series. Preferably, the well fluid conditioning portion 48 may be sized so that the well fluid 14 will remain therein for at least 30 seconds as it passes through the dewatering tool 60 at the desired rate of flow.
Furthermore, the metal spheres disposed in the well fluid conditioning portion 48 may be provided with two or more different diameters. For example, the well fluid conditioning portion 48 may be filled with half copper spheres having ½ inch diameters, and half with 1 inch diameters. Of course, other ratios and diameters may be used. All such embodiments are comprehended by the present invention.
As discussed above, the well fluid contacting structures 42 may be pre-treated to enhance the effect of the well fluid contacting structures 42, or to impart other characteristics on the well fluid 14.
The dewatering tool 60 will now be further elaborated using the following non-limiting example, which yielded good results.
A two foot long dewatering tool 60 was made by the following steps.
A two foot long stainless steel tube was obtained (Pinacle Stainless Steel Inc., Calgary, AB, Canada). The stainless steel tube had an outside diameter of 1 inch, an inside diameter of 0.8 inch, and 1 inch NPT threads on each end.
A pair of 0.8 inch diameter screens 44 were fabricated by plasma cutting 0.8 inch disks from a ⅛ inch (11 gage) thick steel plate (304SS), and drilling 19, ⅛ inch round holes into each disk to form the openings 46.
One of the pair of 0.8 inch diameter screens 44 was welded within the stainless steel tube bore 26, two inches from one end of the stainless steel tube.
Next, the stainless steel tube bore 26 was filled with forty-two solid ½ inch diameter brass spheres (RotoMetals, Inc., San Leandro, CA, U.S.A.). The brass spheres were pre-treated by tuning them in an Enercat™ E1000 for a period of 24 hours, prior to being used to fill the stainless steel tube bore 26.
After filling the stainless steel tube bore 26 with the pre-treated brass spheres, the second of the pair of 0.8 inch diameter screens 44 was welded within the stainless steel tube bore 26, two inches from the other end of the stainless steel tube. In this example, the pair of screens 44 were spaced apart a distance of 20 inches (i.e. about 1 foot and 6 inches), defining a conditioning portion 48 having a volume of about 0.165 liters (10.05 inch3). The distance was calculated according to the formula discussed above, based on an expected maximum extraction rate of 5 BPD.
The dewatering tool 60 was installed in a walking beam pump well 66 with a sandstone hydrocarbon reservoir 16 that had been operating continuously for at least 2 years prior. The dewatering tool 60 was installed in a flow line 62 leading to an oil/water separator 64 from the well head 32. This particular waking beam pump well 66 employed a heater treater 68 connected to the flow line 62 upstream of a 400 barrel oil/water separator 64, and the dewatering tool 60 was installed in the flow line 62 between the well head 32 and the heater treater 68
Prior to installation of the dewatering tool 60, the well operator reported high water content levels (as high as 12%) in the oil phase 70 of the well fluid 14 in the oil/water separator 64, when dewatering chemicals were not used. The water content of the oil phase 70 was measured using the shake-out technique, which physically separates an oil and water mixture by centrifuging. In order to reduce the water content to less than the 1% level needed to produce a vendable product, the well operator implemented a chemical dewatering treatment process to treat the well fluid 14 in the oil/water separator 64, in addition to using the heater treater 68. In particular, the well operator used chemical demulsification, which reduces the interfacial tension between oil and water molecules in the well fluid 14.
After installation of the dewatering tools 60 in the flow line 62, the walking beam pump well 66 was operated normally, but without using chemical dewatering. The use of dewatering chemicals to treat the well fluid 14 in the oil/water separator 64 was discontinued. With the dewatering tool 60 installed, well fluid 14 flowed through the dewatering tool 60 to the heater treater 68 and on to the oil/water separator 64 at an average rate of about 30 BPD. Shake-out samples were measured daily, over a period of 60 days, revealing a reduction in the water content in the oil phase 70 of the well fluid 14 in the oil/water separator 64 down to as low as 0.1%, without the use of dewatering chemicals, or any other dewatering treatment process, apart from using the dewatering tool 60, and the heater treater 68. In other words, the dewatering tool 60 allowed the operator to continue operating the walking beam pump well 66 without needing to resume the use of costly dewatering chemicals. Accordingly, the dewatering tool 60 proved to be a good substitute for the dewatering chemicals.
The results of the experiment are shown in
Shake-out measurements taken at the heater treater 68 are plotted on the graph as scatter points, with a trend line showing a decreasing trend from day 1. While shake-out values measured at the heater treater 68 are not indicative of the values in the oil/water separator 64, they are representative in that higher shake-out values at the heater treater 68 would lead one to expect to see higher shake-out values at the oil/water separator 64. Similarly, lower shake-out values at the heater treater 68 would lead one to expect to see lower shake-out values at the oil/water separator 64. Thus, seeing a decreasing trend in the shake-out values at the heater treater 68, and/or consistently low shake-out values are both positive signs. Shake-out measurements taken at the oil/water separator 64 will usually be lower than the shake-out measurements taken at the heater treater 68 because the well fluid 14 treated with the dewatering tool 60 will have had more time to settle out into the oil and water phases 70,72.
Shake-out measurements taken at the oil/water separator 64 are plotted on the graph as bar lines. The six measurements taken at the oil/water separator 64 were 1%, 0.4%, 0.8%, 1%, 0.5%, and 0.6%, respectively. As can be seen these measurements are all at or below the 1% threshold level needed to produce a vendable product.
A follow up with the well operator four months after installation of the dewatering tools 60 revealed that the walking beam pump well 66 continued to operate without needing dewatering chemicals to treat the well fluid 14 in the oil/water separator 64. Based on this result, it was concluded that the dewatering tool 60 successfully maintained the water content in the oil phase 70 of the well fluid 14 in the oil/water separator 64 at a desirable level of less than 1%, allowing the well operator to continue to operate the walking beam pump well 66 without needing to reinstate the previously required chemical dewatering treatment process.
While reference has been made to various preferred embodiments of the invention, other variations, implementations, modifications, alterations, and embodiments are comprehended by the broad scope of the appended claims. Some of these have been discussed in detail in this specification and others will be apparent to those skilled in the art. Those of ordinary skill in the art having access to the teachings herein will recognize these additional variations, implementations, modifications, alterations, and embodiments, all of which are within the scope of the present invention, which invention is limited only by the appended claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 3204514 | Jun 2023 | CA | national |
