Patent Application
20220364429
The invention relates to methods, devices, and systems for temporary plugging of wells or a portion thereof, and more particularly to methods of removing degradable plugs using a combination of erosive tools and one or more degradation fluids.
Well completion equipment is installed in hydrocarbon producing wells to facilitate the production of hydrocarbons from subsurface formations to the well surface. Temporary plugs are frequently installed in the production tubing or casing or liner to accomplish various tasks. For example, a temporary plug can be installed in the lower end of the production tubing to permit tests for the pressure bearing integrity of the tubing. Additionally, the plug can permit the selective pressurization of the tubing to permit the operation of pressure sensitive tools within the tubing. Another example is the installation of temporary plugs to allow staged fracking of the well.
Temporary plugs are typically removed from the well by mechanical retrieval techniques such as wirelines, slick lines, and coiled tubing. Because other well operations cannot be performed during such work, the retrieval of the temporary plug delays the well operations and adds additional cost to the well operations. Thus, temporary plugs that do not require retrieval have been designed. In particular, several groups have designed degradable plugs that can be solubilized or degraded at will and thereby avoid any mechanical retrieval processes.
U.S. Pat. No. 5,607,017, for example, describes a dissolvable plug that can be used for temporary plugging of a well. These inventors suggest using Series 300-301 dissolvable metal manufactured by TAFA Incorporated of Concord, N.H. Such material has strength and machinability characteristics of certain metals but will disintegrate when exposed to water.
U.S. Pat. No. 9,151,143 describes acid soluble metals including, but not limited to, barium, calcium, sodium, magnesium, aluminum, manganese, zinc, chromium, iron, cobalt, nickel, tin, any alloy thereof, or any combination thereof.
US20150354310 describes dissolvable resin and fiber plugs.
U.S. Pat. Nos. 9,416,903 and 7,493,956 describe hydrate plugs made of low molecular weight gas trapped in solid lattice of water molecule, that can be dissolved by means of heat or by means of a hydrate dissolving fluid, for example methanol, monoethylene glycol (MEG), diesel, and the like. Combinations of heat and dissolving fluids are typically used for this type of plug.
US20050205264 describes plugs made of an epoxy resin, a fiberglass, or a combination thereof, that can be dissolved with caustic or acidic fluids.
U.S. Pat. No. 9,757,796 teaches wrought magnesium dissolvable alloys.
Although a great benefit, some issues remain to be solved with dissolving or otherwise degradable plugs. One problem is the slow speed of degradation, taking upto 2 to 4 weeks for some materials. Another is the frequency at which the plugs do not fully degrade, leaving solid material behind to interfere with flow or subsequent operations. The small pieces can clog nozzles, sensors, and other small devices, and can also plug surface equipment if produced to surface.
The current state of the art in such instances is to apply mechanical energy to remove the solid plug material. For example, a mill can be used to grind out the plug. However, not all wells are ideally suited for mill or other mechanical device usage, especially where the well has a smaller diameter or the casing has deformations. Thus, the problem of solid plug remnants remains in many wells.
Thus, what is needed in the art are better methods, devices, and systems to allow temporary plugs to be completely removed, not leaving behind any non-degraded solid components that can impact well production and/or control equipment. The ideal method will also speed degradation.
The present disclosure provides a new way to remove degradable plugs, wherein the degradation fluid is applied with fluid jets at high pressure, thus applying an erosive force to the plug, in addition to the chemical action of the degradation fluid. Such tools are widely available, and are often of smaller diameter than mechanical tools, and many can be directionally controlled, thus providing a high degree of precision in applying an erosive force to the plug. Plugs that would normally require hours or days to degrade are removable in minutes using combined erosive forces and chemical degradation.
The advantages of the new method include one or more of the following:
Erosive jets can be added to coiled tubing (CT) or other tubing and used in the methods herein. In addition, any existing jet designed for acid tunneling or jet drilling may potentially be used herein, depending on both the plug position and the particular tool design. Such tools are typically deployed at the end of CT and the BHA consists of a jetting nozzle mole and one or more pressure-activated elbow joints that allow the jet to be directed at a variety of angles laterally. If, however, the plug is in-line with the well, the elbow or knuckle joints may not be needed, and can be either omitted or not activated. As yet another alternative, the jet may have a deflection component to direct the jet at 90°, 60°, 45°, or other specified angle from the well direction.
Ideally, the jet mole—the distal tip of the tool that houses one or more nozzles—is optimized in size and shape for the plug type being eroded/dissolved, but this may not be essential, and existing tools may instead be repurposed without modification. Features that are typically optimized for use include number, placement, and angles of nozzles on the mole, shape and size of nozzle openings and thus spray parameters, fixed versus spinning jet moles, and the like. In one embodiment, a turbo nozzle may be used which rotates to cover a larger area with a directed jet.
As one example of optimization, if frac plugs are provided around the circumference of the well, e.g., three at 60° from one another, three nozzles similarly arranged around the periphery of the jet mole may direct degradation fluid at 90° to the jet hose, thus precisely targeting the three frac plugs. If this is combined with a spinning tip even a single nozzle may suffice—the rotation ensuring that all plugs are hit by erosive forces, although wasting force between the plugs. A rotating jet is shown in U.S. Pat. No. 6,062,311 wherein angled baffles/turbines inside the jet mole cause the mole to spin as fluid drives against the baffles.
As another example, the size of the jets is optimized to fully cover at least the size of the plug, and the angle and spread/spray of the jets may be optimized for different plugs. As another example, jets may be provided at more than one angle (e.g., 80, 85, 90° for a lateral jet mole that jets fluids at 90° to the tool and well, or 0, 5, 10° for a linear system that jets fluid in-line with the well), ensuring that the plug is fully degraded even if the contours of the plug are not perfectly cylindrical. In another embodiment, the tool has a fan or 360° spray that erodes the plug evenly across the entire diameter of the casing or wellbore surface, or a conical spray for an inline plug. Modular interchangeable jet moles may be provided for differing plug styles, allowing the main body of the tool to be used for a wide variety of different plugs.
An exemplary tool by Baker Hughes is shown in
Many additional jetting tools are known. Schlumberger Tech. Corp., for example, makes a tool call the Jet Blaster, with a slow rotating nozzle, so energy doesn't just go into faster rotation. Tempress makes the HydroPull SC (Stimulation & Cleanout) engineered with jet nozzles that momentarily interrupt return flow in the completion annulus to create intense water-hammer pressure pulses that vacuum the wellbore, pulling fines and debris from behind completions and out of the formation. Baker Hughes makes the StimTunnel tool with 6 jets arranged on the tip of the tool surrounding a central seventh jet. This is a dual-knuckle tool conveyed by coiled tubing and is available with an optional memory inclinometer gauge to track tunnel trajectory and orientation.
In use, the tool in
In more detail, the invention includes any one or more of the following embodiment(s) in any one or more combination(s) thereof:
A method of temporarily plugging a hydrocarbon well, comprising: providing a section of tubing in a well, said tubing having one or more degradable plug(s) therein, thus providing a plugged section of well; performing a downhole activity in said plugged section of well for a period of time; and providing one or more degrading fluid(s) downhole to degrade said degradable plug, leaving no solid plug material behind and thereby opening said plugged section of well; wherein said degrading fluid is deployed at a high pressure so as to provide an erosive force to completely remove said plug in 50% of the time required to remove said plug without said high pressure and just said one or more degrading fluid(s).
A method of temporarily plugging a hydrocarbon well, comprising: providing a section of tubing in a well, said tubing having one or more degradable plug(s) therein, thus providing a plugged section of well; performing a downhole activity in said plugged section of well for a period of time; and providing one or more degrading fluid(s) downhole to degrade said degradable plug, leaving no solid plug material behind and thereby opening said plugged section of well; wherein said degrading fluid is deployed at a high pressure of 1500 psi so as to provide an erosive force that removes said plug faster than a time required to remove said plug without said high pressure and just said one or more degrading fluid(s).
Any method herein described, wherein said degradable plug is degradable in <24 hours or <48 hours.
Any method herein described, wherein said degradation fluid is applied with a jet.
Any method herein described, wherein said degradation fluid is combined with an abrasive agent.
Any method herein described, wherein said plug is in a side wall of a casing or tubing and said degradation fluid is applied with a jet angled at about 90° to said well. Alternatively, said plug is inline said well and said degradation fluid is applied with a jet angled at less than +/−10° to said well.
Any method herein described, said method further comprising providing one or more blocking devices above and below said section, wherein said blocking devices are selected from a plug, a packer, a basket, or combinations thereof.
Any method herein described, wherein said high pressure is at least about 1000 psi, 1500 psi, or 2000 psi and is provided by a jet.
Any method herein described, wherein said high pressure is at 1500-5000 psi.
Any method herein described, wherein said degradation fluid is an aqueous acid, an aqueous caustic, or an aqueous brine, or said degradation fluid comprises xylene, toluene, chloroform CHCl3, or other aromatic solvent, or said degradation fluid is selected from dimethylformamide (DMF), dimethylacetamide (DMA), dichloromethane CH2Cl2 (DCM), tetrahydrofuran (THF) acetone, hexafluoroisopropanol, or combinations thereof.
Any method herein described, wherein said degradable plug is a threaded plug and wherein said threads are wrapped with a degradable thread tape.
Any method herein described, wherein a first degrading fluid degrades said degradable thread tape and a second degrading fluid degrades said degradable plug.
Any method herein described, wherein a first degrading fluid degrades both said degradable thread tape and said degradable plug.
Any method herein, wherein the aqueous degrading fluid is an acid, such as HCl.
As used herein, “degrading” and its variants are intended to be read broadly to include a variety of chemical processes to remove a component, including processes of solubilizing, melting, disaggregating, monomerizing, and other sorts of chemical degradation or destruction. “Dissolving” by contrast is to become or cause to become incorporated into a liquid so as to form a solution and may be considered to be more narrow, although most practitioners and patents use the term quite loosely.
As used herein, a “degradation fluid” is one that will degrade a degradable plug, leaving no discernable solids. Degradation triggers are usually chemical reactants, with optional accelerators or retarders to provide the desired timing for plug removal, but temperature is also a factor.
Several degradation fluids and degradable materials are known in the art. For example, polyetherurethane (PEU) will degrade in dimethylformamide (DMF) or dimethylacetamide (DMA), polylactic acid (PLA) is degraded in chloroform CHCl3, dichloromethane (DCM) CH2Cl2, tetrahydrofuran (THF), acetone, hexafluoroisopropanol, and the like. Water-soluble polymers including vinyl acetate-ethylene copolymer (VAE), polyvinyl alcohol (PVOH), ethylene vinyl acetate emulsions (EVA), carboxymethyl cellulose (CMC), polyanionic cellulose (PAC), hydroxypropyl methylcellulose (HPMC), and the like will degrade in aqueous solutions. Silicon can be degraded with strong acids, polar organic solvents, or DYNASOLVE 230 (by DYNOLOGY®). Most degradable metals are degraded in acid, such as HCl or synthetic HCl (an aqueous solution of hydrogen chloride that is acidic). Temporary cement plugs may be eroded by water or acids at high pressures. Some elastomeric plugs are degraded in xylene, toluene, chloroform, or other aromatic solvents.
As used herein, a “dissolution fluid” is one that will dissolve a dissolvable plug, leaving no discernable solids.
As used herein, a “degradable plug” is a downhole temporary plug that serves to temporarily plug a well or a portion thereof for a period of time, but will dissolve, melt, disaggregate, or otherwise degrade under specified conditions in a degradation fluid, comprising any one or more of water, solvents, acid, caustic and/or heat. A “dissolvable plug” is one that is primarily removed by dissolution processes, although other processes may of course contribute in the complex downhole environment.
Various degradable materials are used with embodiments of the invention. Such materials include inorganic fibers, for example of limestone or glass, but are more commonly polymers or co-polymers of esters, amides, or other similar materials. They may be partially hydrolyzed at non-backbone locations. Examples include polyhdroxyalkanoates, polyamides, polycaprolactones, polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl alcohols, polyvinyl acetate, partially hydrolyzed polyvinyl acetate, and copolymers of these materials. Polymers or co-polymers of esters, for example, include substituted and unsubstituted lactide, glycolide, polylactic acid, and polyglycolic acid. Polymers or co-polymers of amides, for example, may include polyacrylamides.
Materials that degrade at the appropriate time under the encountered conditions are also used, for example polyols containing three or more hydroxyl groups. Polyols useful in the present invention are polymeric polyols that solubilize upon heating, desalination or a combination thereof, and consist essentially of hydroxyl-substituted carbon atoms in a polymer chain spaced from adjacent hydroxyl-substituted carbon atoms by at least one carbon atom in the polymer chain. In other words, the useful polyols are preferably essentially free of adjacent hydroxyl substituents.
In one embodiment, the polyols have a weight average molecular weight greater than 5000 up to 500,000 or more, and from 10,000 to 200,000 in another embodiment. The polyols may if desired be hydrophobically modified to further inhibit or delay solubilization, e.g., by including hydrocarbyl substituents such as alkyl, aryl, alkaryl or aralkyl moieties and/or side chains having from 2 to 30 carbon atoms. The polyols may also be modified to include carboxylic acid, thiol, paraffin, silane, sulfuric acid, acetoacetate, polyethylene oxide, quaternary amine, or cationic monomers.
In one embodiment, the polyol is a substituted or unsubstituted polyvinyl alcohol that can be prepared by at least partial hydrolysis of a precursor polyvinyl material with ester substituents. Although it is normally not necessary, the degradation may be assisted or accelerated by a wash containing an appropriate dissolver or that changes the pH or salinity. The degradation may also be assisted by an increase in temperature.
Preferred polymers may include polyglycolic acid (PGA), polylactic acid (PLA), polycaprolactones (PCL), polyethylene terephthalate (PET), polybutylene adipate terephthalate (PBAT), polybutylene succinate (PBS), and the like.
The degradable metal alloys are usually alloys of magnesium or aluminum, and exemplary metal alloys are e.g., Magnalloy by Bubbletight (TX), Elite™ Dissolvable Magnesium Alloy by Fivestar Downhole Service (TX).
An exemplary biodegradable polymer is Kyron™ BP Resin by Mitsubishi Advanced Materials.
As used herein a “jet” is a tool that expels a degradation fluid at high pressure so as to provide significant erosive force in addition to the chemical action of the degradation fluid. In its simplest form, a simple hose with narrowed opening acts as a jet, but typically the nozzle is specifically designed to further increase the force of the fluid, and there may be elbows or other features to direct the jet, various connectors, and the like.
For example, an aluminum plug dissolved with HCl would normally require 2-4 weeks to remove. However, using a jet tool to apply the HCl, the time would be at least reduced in half (1-2 weeks), although preferred dissolution would occur within 48-72 hours or even 12-24 hours. If combined with high temperatures, abrasives, ultrasonic cavitation, and the like, a plug may be completely dissolved with a jet erosive tool in less than 1 day, and even in hours.
In some embodiments, the fluid emitted from the jet may be combined with ultrasonic cavitation and/or abrasives, which will significantly increase the speed of plug degradation. See e.g., U.S. Pat. No. 6,474,349.
As used herein, a “high pressure” is that erosive pressure of degradation fluid that speeds the degradation of a solid, flat, disc of plug material at 90° to a same diameter jet by at least 50% when compared the same plug just soaking in said degradation fluid under the same conditions (typically 22° C. and 1 atm, but temperature can be increased if needed for the material in question). The force exerted by a jet of fluid on a flat surface can be resolved by applying the momentum equation (see e.g., uta.pressbooks.pub/appliedfluidmechanics/chapter/experiment-5/). Thus, a 2 cm disc material that degrades in 48 hours in a bench top experiment, will be completely degraded in 24 or fewer hours by a 2 cm jet under high pressure, where conditions are otherwise the same except for the high pressure application of the erosive fluid. Ideally, the time decrease will be 75%, 80%, 85%, 90%, 95% or more. Typical pressures are about 1000 psi, 1500 psi, and 2000 psi, and go up to 5000 psi, but pressures may be reduced if combined with abrasives and/or cavitation and achieve the same speed of degradation.
As used herein, an “erosive force” is a force that is applied by a fluid. It excludes mechanical forces that are supplied by tools, such as mills and drills.
As used herein, a “tape” or “thread tape” is a long flat strip of material that can be used to seal the threads or other connecting surfaces.
As used herein, a “degrading tape” is one that dissolves, melts, disaggregates, or otherwise degrades under specified conditions in a degradation fluid, leaving no discernable solid remnants in the downhole environment. A “dissolving tape” is a tape that is primary dissolved, although other processes can contribute to tape removal.
“Tubular” or “tubing” can be used generically to refer to any type of oilfield pipe, such as drill pipe, drill collars, pup joints, casing, production tubing and pipeline. One type of tubing used herein is coiled tubing—a thin tube stored in a coil and often used to deliver fluid to the jets.
As used herein, a “joint” is a length of pipe, usually referring to drill pipe, casing or tubing. While there are different standard lengths, the most common drill pipe joint length is around 30 ft (9 m). For casing, the most common length of a joint is 40 ft (12 m).
As used herein, a “tubular string” or “tubing string” refers to a number of joints, connected end to end (one at a time) so as to reach down into a well, e.g., a tubing string lowers a sucker rod pump to the fluid level. “Casing string” has a similar meaning, as applied to casing.
As used herein, the “jet mole” is a term of art in high pressure water cleaning and is evocative of the burrowing mammal. It refers to the nozzle assembly at the distal tip of the tool which houses one or more nozzles.
The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise.
The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated.
The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.
The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim. The phrase “consisting of” is closed, and excludes all additional elements. The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention. Any claim or claim element introduced with the open transition term “comprising,” may instead use the phrases “consisting essentially of” or “consisting of” However, the entirety of claim language is not repeated three times verbatim herein in the interest of brevity.
The following abbreviations or terms are used herein:
Developed herein are methods of temporarily plugging a well, systems of temporarily plugged wells, and tools for use in same. Several degradable plugs are commercially available, including e.g., Halliburton Illusion™ frac plug, Vertechs WIZARD MS™ frac plug, Magnum Oil Fastball™ frac ball, Innovex SWAGE™ frac plug, and Baker Hughes SPECTRE™ frac plug, and the like. In addition, several more are described in the patents referenced herein.
When the degradable plug is no longer needed, it is removed by its degradation fluid which is provide by jet under high pressure directly at the plug, so as to speed its degradation by at least 50%. Thus, not only is plug removal faster, but the probability of solid remnants is also much reduced.
If desired, the degradable plug may be combined with degradable thread tape, as described in U.S. Ser. No. 11/053,762. Ideally, both the plug and the tape would degrade under the same degradation fluids, but it is also possible to use two fluids sequentially, if needed. If this is done, it may be preferred to dissolve the tape in advance of the plug, thus improving access to the plug by the degradation fluid.
The enlargement in
The tool designs of
The cross section of well and reservoir 300 in
The cross section of well and reservoir 400 in
The cross section of well and reservoir 500 in
The objective of this test was to demonstrate proof of concept, using a commercially available tool (StimTunnel tool by Baker Hughes—developed for use in jetting away limestone) would be able to erode dissolvable plugs as a method to clean out wells post-stimulation.
The testing consisted of 4 different styles of degradable ball plugs from 4 separate vendors. These plugs were the Innovex's dissolvable frac ball, Yellow Jacket M1 Frac plug, Steel Haus's ReacXion complete plug, and Kureha Degradable Plug (KDP).
All plugs are dissolvable in aqueous solution and were set in 7′ joints of 5½″, 23 ppf casing. The plugs were not exposed to elevated temperatures, fluids, or differential pressure. Each casing joint was installed in the test fixture and the StimTunnel BHA was placed in the casing on top of the plug. The 2.75″ OD version of the StimTunnel was used for the Innovex frac balls and the 2.50″ OD version was used for the rest.
TEST 1 GENERAL: The first round of tests was performed on all 4 plug types and consisted of simply jetting with fresh water with the StimTunnel tool. The tool was run pressed onto the face of the plug with a nominal amount of force while the balls were on seat. At periodic intervals pumping was stopped and the plug face was inspected. During the last 45-60 min the ball (or what was left of it) was removed and the tool pumped on the plug body only.
TEST 1A: Innovex This test consisted of 192 min of pumping, 161 min of which was done with ball on seat and 31 min was done after the ball was removed. The ball was difficult to keep on seat, and so the plug leaked for the entire duration of the test. In this test the casing between shutdowns was also rotated. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi. Pumping and inspection occurred 5 times in this test.
Moderate erosion was seen on the plug and ball while the ball was partially in place. A much higher amount of erosion was seen once the ball was removed. The design of the top of the plug caused the StimTunnel tool to center on the plug. The jets appeared to be able to erode the length of the plug, but due to the smaller plug ID and the 0° angle of the jets, the tool would not have been able to pass through the cored out plug. If acid sweeps were used, it would be likely the plug would have lost integrity and started to break apart with a combination of erosion and dissolution.
TEST 1B: Yellow Jacket The test consisted of 163 min of pumping, 118 min of which was done with the ball on seat and 45 min with the ball removed. The ball was epoxied on to the seat by the vendor and thus held fluid for 73 min. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi. Pumping and inspection occurred 3 times in this test.
Slight erosion was seen on the plug and ball while the ball was in place. Moderate erosion was seen once the ball was removed. Due to the geometry of this plug, the StimTunnel remained on the low side of the casing and did not self-center on the plug. One of the seven jets was able to work on the plug body, ˜2″ below the ball seat. It appeared that fluid breakthrough occurred when that jet cut the plug body and found a path into the setting mechanism. If acid sweeps were used, it would be likely the lock ring would have been attacked from below, allowing the plug to collapse.
Test 1C: Steel Haus. The test consisted of 160 min of pumping, 121 min of which was done with ball on seat and 39 min was pumped with the ball removed. The ball was epoxied on to the seat but only held fluid for 10 min. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi. Pumping and inspection occurred 3 times in this test.
Moderate erosion was seen on the plug and ball while the ball was in place. Very little erosion was seen after the ball was removed: the 2.50″ OD nozzle centered into the 2.50″ ball seat, causing almost all the rate to be directed through the center nozzle leaving little erosive force on the other 6 nozzles. However, while the ball was in place, the BHA was off-center and worked on the sealing element of the plug. The top of the element was ˜1″ below the ball seat and the jet appeared to erode ˜0.5″ of element and cut through the retaining ring. It appeared that fluid breakthrough occurred when that jet cut the plug body and found a path into the setting mechanism. If acid sweeps were used, it would likely have attacked the element and then the slips, causing the plug to unseat.
Test 1D— Kureha The test consisted of 157 min of pumping, 78 min of which was done with ball on seat and 79 min with the ball removed. The ball was left loose on the seat and held fluid for 2 min. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi. Pumping and inspection occurred 2 times in this test.
Moderate erosion was seen on the plug and slight erosion on the ball while the ball was in place. Significant erosion was seen after the ball was removed. At ˜15″ this was the longest of all the plugs tested; while the erosion was probably the deepest of all the tests the nozzle would have to penetrate greater than ˜7″ to begin working on the sealing elements. Most of this plug is made of plastic that is not affected by acid or chlorides but degrades mostly by temperature.
The second round of tests were performed on 3 of the 4 plugs (the long Kureha plug was excluded from this test). In this test, silica flour (200 mesh) was mixed into a 20 # gel (160 lbs silica per 20 bbl tub) at 0.2 ppg. The StimTunnel tool was then placed ˜1 inch above the plug face with the ball on seat. Twenty-one barrels of the abrasive solution was then pumped over an 8-9 min period.
Test 2A: Innovex The test consisted of 8 min of pumping a solids-laden fluid consisting of a 0.2 ppg silica flour in a 20 # gel. The ball did not stay on seat, and so the plug leaked for the entire duration of the test. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi.
Significant erosion was seen on the plug and the ball. However, the same issue in Test 2 was noted as observed in Test 1 with the nozzle wanting to bore a hole through the plug without attacking the slips or sealing element, indicating the value of nozzle optimization for the plug at issue.
Test 2B: Yellow Jacket The test consisted of 16 min of pumping a solids-laden fluid consisting of a 0.2 ppg silica flour in a 20 # gel. This test was pumped in 2 stages of 21 bbl each. The ball was epoxied on seat, and initially held fluid. Approximately 5 min into the pumping the plug began leaking. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi.
Significant erosion was seen on the plug and the ball. However, the same issue was noted with the nozzle wanting to bore a hole through the plug without attacking the slips or sealing element.
Test 2C: Steel Haus The test consisted of 8 min of pumping, a solids-laden fluid consisting of a 0.2 ppg silica flour in a 20 # gel. The ball was epoxied in place and initially held fluid. The plug began leaking 2 minutes into the test. The pump rate varied anywhere between 95 gpm to 105 gpm and pressures from 4400-4500 psi.
Significant erosion was seen on the plug and the ball. However, the same issue was noted with the nozzle wanting to bore a hole through the plug without attacking the slips or sealing element.
Overall, the testing showed that the plugs are sensitive to erosion, and are predicted to speed degradation significantly, although head-to-head testing still needs to be done. The results also indicate that further testing is warranted with optimized nozzles, plus and minus acid, and plugs that have been exposed to typical downhole corrosive conditions.
We observed that the nozzles that were directly in contact with the plug/ball did the least amount of work. It is hypothesized that the back pressure formed (as there was no escape path for the jetting fluid) caused the flow rate to be diminished at that nozzle and thus be less effective. The addition of water courses on the jetting tool could correct this issue.
For locations where casing deformation is not an issue, a larger OD nozzle should be effective, e.g., a drift nozzle (a larger OD nozzle, closer to the ID of the casing) can be utilized. This will allow the erosive jets to work along the outside of the plug, attacking the slips and sealing element. The pressure drop across the nozzle may need to be adjusted in certain wells due to high well head pressures.
In locations where deformation creates restrictions, the nozzle pattern needs to be altered due to use of an undersized BHA. The existing 2.50″ OD StimTunnel tool may not cut a large enough hole to allow drift of the tool itself.
While the ability to pump acid will probably be the biggest positive for implementing this invention downhole, changes to the geometry of the tool are also expected to be beneficial. Providing a variety of jet moles—each optimized to accommodate a different plug style—allows the same BHA body to be used to erode many different plugs, merely by switching out the jet mole.
Proposed changes for further testing may include:
1) The StimTunnel diameter and overall configuration needs to account for specific plug geometry. For instance, an observation from Test 1C is that the ball seat diameter and the BHA diameter need to be different.
2) Changing the face geometry of the nozzle so that the BHA can “move” the ball off seat could be beneficial as the ball appeared to be the biggest hinderance to erosional force. By moving the ball off center, it should allow some erosional action to begin working on the plug body.
3) Giving the nozzles some directional paths could allow for more destructive erosion by allowing it to cut across the plug rather than just through the center of it.
4) Changing the nozzle exit angle from 0° to 10-20° could allow making ‘cuts’ rather than boring holes through the plug.
5) Targeted acid sweeps throughout the erosional process could also be very beneficial.
6) Silica flour sweeps greatly increased the rate of erosion, but did not necessarily change tunnel geometry. The StimTunnel nozzles showed some degradation from erosion from the silica flour, but that was not unexpected since the tool was not designed to accommodate abrasives. A toughened tool will be able to accommodate abrasives.
Speculating about actual well bore conditions, we believe that a partially degraded plug should be considerably weaker, particularly if it has aged significantly in a corrosive environment. Thus, when material is being eroded away the loss of integrity may cause the plug to fall in on itself allowing the jetting action to ‘push’ the debris down hole. This would also continue to increase the surface area and speed along the dissolution process. It is probably not sufficient to simply push a weakened plug body deeper into the hole. The BHA likely needs to be able to cut the weakened body into very small pieces so they can fully degrade and allow the BHA to contact the next plug.
In the case of a plug that has a lock ring (e.g., Yellow Jacket and Steel Haus), if the erosion attacks the lock ring, the plug should fall apart relatively easily. If the jets can attack the weakened sealing element (Steel Haus), this should accelerate the plug's failure. Thus, this is one of the proposed optimization targets for jet mole optimization.
The longer the plug, the more difficult erosion will be because the erosion does not happen uniformly across the plug body. The erosion tunnels must attack parts of the plug that will cause plug failure (e.g. lock ring, sealing element, etc.). If these elements are far from the top of the plug, it will take much longer to work through.
Using abrasives accelerated the erosion process significantly. However, as the plugs will most likely be in a semi-dissolved state when encountered downhole the abrasives may not be very helpful unless the ball is still mostly intact. On the plugs with larger balls, abrasives could be useful in quickly eroding past the ball to begin working on the plug body. With semi-dissolved plugs, application of acid along with erosive force will probably be most effective, but further testing will need to be done to confirm our predictions.
Our proof of concept testing thus showed a benefit for additional testing to optimize certain features:
1) Optimized BHA. We plan to test jets having larger OD, different nozzle patterns, different nozzle angles, and the like. Preliminary design considerations can be tested computationally, using, for example, Computational Fluid Dynamics (CFD) software, and optimized models tested physically, in a manner similar to the tests described herein.
2) Realistic Test Conditions. We plan to repeat tests by first heating up the plugs for 24-48 hours to test more realistic degradation conditions. In addition, we will have no jet comparisons to prove the increased speed of degradation.
3) Repeat tests with acidic solutions.
The following documents are incorporated by reference in their entirety for all purposes:
This application claims priority to U.S. Ser. No. 63/188,806, titled, DISSOLVABLE PLUG REMOVAL WITH EROSIVE TOOL, filed May 14, 2021, and expressly incorporated by reference in its entirety for all purposes.
| Number | Date | Country | |
|---|---|---|---|
| 63188806 | May 2021 | US |
