Smart plungers measuring wellbore buildup

Abstract

A method of monitoring deposits on a well by cleaning a well of existing deposits sufficiently to allow a plunger from an instrumented plunger lift to travel therethrough; monitoring any further addition of deposits using the same instrumented plunger lift that records a velocity and a position of the plunger (or any other parameters that allows one to estimate speed and depth) as it travels through the well; and using the recorded velocity and position to determine a size and a position of each added deposit by a decrease in the velocity at a given position as compared to a baseline velocity. Ideally, once added deposits begin to impinge on production rates, the operator then treats said well to remove each said added deposit. The technology may thus be used to identify potential deposits, but also use to validate the efficacy of chemical treatments used in said well.

Description

PRIOR RELATED APPLICATIONS

[0001] This Application claims priority to U.S. Ser. No. 63 / 737,634, filed Dec. 21, 2024 and incorporated by reference in its entirety for all purposes.FEDERALLY SPONSORED RESEARCH STATEMENT

[0002] Not applicable.FIELD OF THE DISCLOSURE

[0003] The disclosure generally relates to method of assessing and thereby mitigating wax and other buildup of deposits in wellbores.BACKGROUND OF THE DISCLOSURE

[0004] Wax deposition is one of the most challenging flow assurance issues in oil production processes. Wax problems span from reservoirs to refineries, but their consequences can be particularly challenging when the affected area is difficult to reach, such as down producing wells.

[0005] Wax will deposit on tubing downhole due to the cooling that occurs as the oil flows from the high-pressure, high temperature reservoir to the surface. As the flow temperature decreases below the cloud point (temperature below which wax forms a cloudy appearance) or wax appearance temperature (WAT), wax precipitation can occur. This hinders flow by triggering non-Newtonian behavior. The crude viscosity exponentially increases as the temperature reaches the pour point (temperature below which liquid becomes semi-solid and loses its flow characteristics). Consequently, a layer of sticky, freshly precipitated paraffin waxes begins to develop. Over time the crystallized wax particles aggregate to form a continuously growing paraffinic layer that may cause plugging of the well and equipment.

[0006] Large-scale wax deposits are easily detected by an associated production rate decrease. However, detecting nascent deposits is more difficult and is critical for assuring flow conditions, production in the long run, avoiding downtime and preventing costly interventions.

[0007] Thus, several methods have been developed for measuring the wax thickness in pipelines. For example, Chen (1997) reviewed existing wax thickness measurement techniques, including the most common way for detecting wax deposits downhole, which is the pressure drop method. The process of wax deposition results in an increase of the pressure drop gradient and there are equations to relate the pressure drop to a decrease in tubing diameter. Other techniques reviewed by Chen include pigging, spool piece, and heat transfer methods.

[0008] Chen (1997) also presented an on-line wax thickness measurement technique, called the liquid displacement-level detection method. Later he described a pressure wave propagation technique to find the blockage location by measuring the time spent by a pressure wave to be reflected back along the pipeline from the point of blockage (Chen (2007)).

[0009] Yet another technique uses calipers and a video camera on a remotely operated submersible to measure the pipeline diameter.

[0010] However, not all of the above options are viable solutions for downhole wells and methods to predict or detect wax blockages inside producing wells still need to be improved. Table 1 (excerpted from Sousa 2019) presents some of the disadvantages of the various existing techniques.TABLE 1Advantages of wax deposit identification methods (from Sousa 2019)MethodAdvantagesDisadvantagesPressure dropThe location of wax deposits along the wellDue to the complexity of pressure dropmethodand its thickness investigation can beassociated with multiphase flow, thisobtained from accurate measurements ofmethod is not adequate to determine waxfrictional pressure drops, for single-phasethickness in multiphase flow.flow. This method does not requireAnother shortcoming is the inability todepressurization and restart to obtain theprovide information about wax non-measurements and does not impose anyuniform circumferential distribution.influence on the in situ and overall heattransfer.Heat transferNon-intrusive method (Chen et al. 1997).This method is not suitable for multiphasemethodflow because predicting multiphase heattransfer inside the pipe remains anunsolved issue. Furthermore, there areflow patterns, like slug flow, for instance,that conduce to a non-uniform heattransfer coefficient, challenging theapplication of heat transfer method.Pressure waveThis method has advantages over theCritical hindrances are associated withpropagationsteady-state analysis methods, since it canpowering the devices and generatingmethodpredict the characteristics of the blockage.sufficiently powerful signals to overcomethe large signal attenuation related withwave propagation (Franconi et al. 2014).

[0011] Thus, what is needed in the art are improved methods of detecting and / or measuring wax build up in downhole wellbores. The ideal method would be capable of ascertaining where deposits are located, as well as size, length, thickness, and amount of occlusion for each deposit at each location. Furthermore, it would be cost effective, minimize or eliminate any downtime and use readily available equipment. This invention addresses one or more of these needs.SUMMARY OF THE DISCLOSURE

[0012] This disclosure relates to a novel way to ascertain the presence, location and / or size of any buildup inside a tubing string, production tubing, casing, or other tubular using an instrumented plunger lift, and mitigating the damage that may be caused by such damage.

[0013] Production engineers consider plunger lift to be one of the simplest forms of artificial lift because it uses the well's own energy to remove accumulated liquids and sustain gas production. Plunger lifts are being increasingly used in artificial lift, including gas assisted plunger lift, and plunger assisted gas lift of downhole fluids, because they offer an economical technique for removing liquids from aging gas wells while minimizing gas losses and methane emissions.

[0014] Whether the system is used in a gas or oil well, the mechanics of a plunger lift system are the same. The plunger or piston drops from the proximal end of the tubing string or wellhead and travels through the production tubing to the bottom of the well where it lands on a bottomhole bumper spring or other receiver (FIG. 1). Pressure buildup drives the plunger (and fluid above the plunger) back to the surface, where the cycle begins again.

[0015] The plunger has enough clearance to allow it to move unhindered up and down the tubing string, however, the clearance is small enough to create a fluid interfacial seal between the fluids above and fluids or gas below the plunger. The mechanism would be similar to forming a slug of fluid, but without a plunger, the fluid interface could be disrupted allowing gases and fluids to mix allowing fluid fallback. With the plunger a clean separation is created between the produced fluids and the plunger allowing for more complete fluid removal.

[0016] Visible in FIG. 1 are the lubricator 101 for providing access to the plunger to be inserted into or retrieved from the well, retrieve data from the plunger, and transmit data to a network or processor for analyzing the data. Also seen are the catcher 104 and catcher sensor 103, which holds the plunger in the lubricator and allows the plunger to be removed or switched out for a different style of plunger, the wellhead 105, tubing 107, and casing 109. Further included may be a tubing stop, collar stop, or other stopping mechanism, hold down in profile nipple, a standing valve at the distal end of the tubing 111, as well as a bottom hole bumper spring 113 to cushion the dropping plunger 115.

[0017] Fluid 117 and gas 119 are lifted as the plunger lifts, driven by gas from below and exit via flow line 121. Motor valve 123 and controller 125 control the plunger and in this instance, power may be provided by solar panel 127. An onsite generator, transmission lines or other power source could be used instead, depending upon the location and resources available.

[0018] Early in plunger lift, a simple rapid flow or continuous flow plunger can be used where the plunger 115 has two different modes actuated by contacting the bumper spring or upon release of pressure in the lubricator. The rapid or continuous flow plunger is inserted into the lubricator in an open position with open flow through the plunger. The plunger drops to the bottom of the well where, upon contact with the bumper spring 113, the flow through the plunger is closed pushing the plunger toward the surface. Once the plunger reaches the surface, a drop in pressure upon passing the sales flowline 121 opens flow through the rapid or continuous flow plunger allowing the plunger to drop again, where the cycle is repeated as the plunger is closed again on the bumper.

[0019] Plunger lift operation is thus a cyclical process of shut-in (or no-flow) and flow periods as shown in FIG. 2. The cycle begins in the shut-in mode with the plunger 115 resting on the bottomhole bumper spring 113 at the distal end of the tubing. The surface valve 123 is in the closed position, which allows well pressure to build in the annular space between the casing and the tubing. The controller opens the surface valve after a predetermined time, pressure increase, fluid accumulation, gas or fluid flow rate, or other parameter required to optimize fluid production. The difference in pressure between the sales or flow line and the reservoir drives the plunger and any fluids toward the surface or proximal end of the well. As it rises, the plunger pushes the fluid column above it to the surface. The fluids above the plunger flow through an upper and lower outlet on the wellhead lubricator and into the flowline 121. The plunger arrives in a spring-loaded receiver in the lubricator. The controller then closes the surface valve 123 and the plunger 115 falls back down to the bottomhole bumper spring 113. The cycle begins anew as liquid loads above the plunger and annular gas pressure builds.

[0020] Controlling the plunger travel speed and cycle times is critical to safety and efficiency. Therefore, plunger lift operations have incorporated various smart technologies. Electronic controls that have solid-state circuitry regulate the cycling of the motor valve in response to plunger arrival at the wellhead, line pressures, liquid levels or pressure differentials. These controllers also help streamline its use and save hours required to manually fine-tune the plunger system, optimize production parameters, and monitor well conditions.

[0021] New information technology systems, such as smart automation, online data management and satellite communications, have streamlined plunger lift monitoring and control by enabling operators to manage plunger lift systems remotely, without the need for routine in-person field visits.

[0022] Wireless monitoring and control systems that transmit analog or digital signals via radio or from a central processing device are gaining greater acceptance, particularly among operators using plunger lift in many hundreds or thousands of wells. Wireless systems can be set up on location in less than an hour, as opposed to the several days required for conventional wired systems, and without the need for conduits or trenches for buried cables. The ability to wirelessly transmit sensor data, which may include liquid level, flow rates, pressure, temperature, plunger location, and system alarms, may allow a plunger lift system to be monitored remotely and in real time or near real time. Operators use this information to optimize their field crew deployments by sending crews to only those wells that require maintenance or repairs, increasing efficiency and reducing costs.

[0023] With a so-called “smart” plunger lift system, we can repurpose these existing technologies to monitor deposition of wax, scale and other deposits on tubing walls. Since the clearance between the plunger and the wellbore is small, the plunger is not deployed inside a well with heavy deposits until those deposits have been removed, e.g., with heat, chemicals, and the like. However, once a wellbore is sufficiently clean, the smart plunger may be deployed to collect a baseline. The velocity of travel of the plunger through the tubing can be obtained directly from the instrument that measures plunger velocity, or inferred where the instrument has a collar counter from the time between collar detections and knowledge of joint length. As yet another option, travel time through the whole well can be used as an estimate of speed, although this alone may not precisely locate the buildup.

[0024] The smart plunger is then deployed at regular intervals thereafter to detect slowdown in plunger travel due to deposits. Once slowdowns are detected, mitigation procedures can be employed to prevent further degradation. If the plunger is also in use for fluid lift, the data can be read by regular data collection and analysis for this purpose, as described in more detail below, either by pulling the plunger (or memory stick) to download data at suitable intervals, or by contact-driven or wireless collection of data at the top of the cycle which may be continuous (e.g. at each cycle) or intermittent.

[0025] Once deposits are detected, they can be mitigated by any means known in the art or to be developed, thus preventing excessive build up and production slowdowns or loss. There are a range of methods for removing paraffin wax build-ups in oil wells and equipment, but they can be grouped into three main types by mechanism of action: 1) mechanical, 2) thermal, and 3) chemical. Of course, many methods employ combinations of these basic methodologies.

[0026] Mechanical—Scrapers and cutters are used extensively to remove wax and other deposits from tubing because they can be economical and result in minimal formation damage. Scrapers may be attached to wireline units, or they may be attached to sucker rods to remove wax as the well is pumped. Here, the plunger itself may be switched out for a plunger with wipers.

[0027] Another method of mechanical intervention that helps prevent deposition is the use of plastic, coated, or chemically treated pipe. In one embodiment, pipe surfaces may be treated with self-assembling monolayers (SAM) to reduce or prevent wax deposition as described in U.S. Ser. No. 12 / 097,538. Low-friction surfaces make it more difficult for wax crystals to adhere to the pipe walls. Deposition will still occur if conditions are highly favorable for wax precipitation, and deposits will grow at the same rate as for other pipes once an initial layer of material has been laid down; therefore, the pipe and coating system must be capable of withstanding one of the other methods of wax removal.

[0028] Thermal—Because wax precipitation is highly temperature dependent, thermal methods can be highly effective for both preventing and removing wax. Prevention methods include steam- and electrical-heat tracing of flowlines in conjunction with thermal insulation. Thermal methods for removing wax depositions include hot oiling and hot watering. In one embodiment heated water is cycled through the well periodically to reduce or prevent paraffin build-up as described in U.S. Ser. No. 10 / 161,224. Hot water treatments do not provide the solvency effects that hot oiling can, so surfactants are often added to aid in dispersion of wax in the water phase, but surfactants are discussed under chemical methods.

[0029] Hot oiling is one of the most popular methods of deposited wax removal. Wax is melted and dissolved by hot oil, which allows it to be circulated from the well and the surface producing system. Hot oil is normally pumped down the casing and up the tubing; however, in non-flowing wells, the oil may be circulated down the tubing and up the casing. There is evidence that hot oiling can cause permeability damage if the melted wax enters the formation.

[0030] Higher molecular-weight waxes tend to deposit at the high-temperature bottom end of the well. Lower molecular-weight fractions deposit as the temperature decreases up the wellbore. The upper parts of the well receive the most heat during hot oiling. As the oil proceeds down the well, its temperature decreases and the carrying capacity for wax is diminished. Thus, sufficient oil must be used to dissolve and melt the wax at the necessary depths.

[0031] Unfortunately, any heat-based method tends to be somewhat less effective in colder climates. As the hot fluids inevitably cool, the wax can once again recrystallize and again form deposits. Thus, thermal methods are often combined with other methods to improve efficacy.

[0032] Chemical—The types of chemicals available for paraffin treatment include solvents, wax crystal modifiers, dispersants and surfactants. There are also various chemicals to remove scale and corrosion. In one embodiment, wax deposits are removed with specialized chemical formulations that form micro-emulsions with the paraffin as described in U.S. Ser. No. 11 / 427,749.

[0033] Solvents can be used to treat deposition in production strings and may be applied to remediate formation damage. Solvents are mostly used in large batch treatments. Although chlorinated hydrocarbons are excellent solvents for waxes, they generally are not used because of safety and processing difficulties they create in the produced fluid.

[0034] Hydrocarbon fluids consisting primarily of normal alkanes such as condensate and diesel oil can be used, provided the deposits have low asphaltene content. Aromatic solvents such as toluene and xylene are good solvents for both waxes and asphaltenes.

[0035] Wax crystal modifiers act at the molecular level to reduce the tendency of wax molecules to network and form lattice structures within the oil. Wax crystal modifiers that act to reduce oil viscosity and lower the wax gel strength are only effective when used continuously. Since they work at the molecular level, they are effective in concentrations of parts per million, as opposed to hot oil or solvents, which must be applied in large volumes. However, wax crystal modifiers have a high-molecular-weight and as a result they have high pour points, so their use may be limited in cold climates.

[0036] Dispersants are a type of surfactant that helps disperse the wax crystals into the produced oil or water. This dispersing of the wax crystals into the produced oil or water helps prevent deposition of the wax and also has a positive effect on viscosity and gel strength. Dispersants can help break up deposited wax into particles small enough to be carried in the oil stream. To prevent wax deposition, dispersants must be used continuously, but to remediate deposited wax, dispersants can be used either continuously or in batch treatments. One advantage is that dispersants generally have a very low pour point making their use suitable for cold climates. These chemicals are used in low concentrations and can be formulated in both aqueous and hydrocarbon solutions, making them relatively safe and inexpensive.

[0037] Surfactants are a general class of chemicals that are most often used to clean vessels, tanks, pipes, machinery or any place where wax may deposit. Surfactants or dispersants can also be used in combination with hot oil and water treatments.

[0038] Before choosing a chemical to remove paraffin deposits it is important to first consider the nature of wax build-ups. Oil wells that suffer from wax problems are, in fact, usually experiencing other type of fouling as well.

[0039] Many chemical treatments for paraffin in use today require heat in order to be most effective. The application of heat into the system requires additional equipment, energy usage and expense so it is preferable to choose chemicals that are effective at lower temperatures.

[0040] The final and most important consideration when selecting the best paraffin removal chemical is safety. Many chemical treatments require the use of caustic reagents that are hazardous to workers and can damage equipment. Many solvent-based treatments contain toxic chemicals that increase risks to human health and the environment.

[0041] There are many plunger styles that can be used herein, including e.g., the continuous flow (bypass) plunger, the ball and sleeve style plunger, diamond cut plungers, fast fall plungers, as well as conventional plungers. However, there must be some way of ascertaining plunger speed and / or location, and smart plungers are preferred as already having the necessary sensors and / or communication means. As an alternative, an existing plunger can be converted to a smart plunger by adding the necessary sensors, processors and memory.

[0042] Any plunger that records plunger velocity, either descending or ascending velocity, may be used. Plungers that measure velocity ascending and descending are commercially available. GOTEK SYSTEMS™, for example, has a modular instrumented plunger called the “I-PLUNGER™” (see FIG. 3 and description same) that is equipped with a pressure transducer, temperature transducers, and a collar locater. The GOTEK smart plunger allows producers to easily acquire downhole data never before available, including velocity, acceleration / deceleration, vertical axis, time, pressure, temperature, depth, clearance, and combinations thereof as well as fluid properties such as flow, viscosity, density, conductivity, and combinations thereof. Different cap adaptors allow users to change the I-PLUNGER™ base for various applications, and includes solid base, dart bypasses, and a two-piece ball and sleeve base.

[0043] Alternatively, a triaxial sensor or other velocity sensor, processor, recorder and power supply may be incorporated any mechanical plunger as such technology, similar to that incorporated into smart watches and air tags, has become very small, durable, and versatile.

[0044] It is even possible to use a plunger without these smart systems, using time of travel alone as deposits will increase the time for travel. However, a smart plunger will also allow one to determine the location of a slowdown and is preferred.

[0045] Preferably, the method is used in cased wells to detect buildup on the inner walls of the casing or other tubing, but plunger lift systems can be used in both cased and uncased wells.

[0046] The invention includes any one or more of the following embodiment(s) in any combination(s) thereof, but each possible combination is not separately listed in the interests of brevity.

[0047] A method of monitoring deposits on a wall of a downhole well, said method comprising: a) cleaning a well of existing deposits sufficiently to allow a plunger from an instrumented plunger lift system to travel therethrough (unless said well is already sufficiently clean); b) monitoring addition of deposits using said instrumented plunger system to record a velocity of said plunger as it travels through said well; and c) using said recorded velocity to determine a size and approximate position of each added deposit by a decrease in said velocity as compared to a baseline velocity.

[0048] A method of reducing wax deposits on a wall of a downhole well, said method comprising: a) monitoring addition of wax deposits in a vertical well using an instrumented plunger lift system to record a velocity and a position of said plunger as it travels through said well; and b) using said recorded velocity and position to determine a size and a position of each added wax deposit by a decrease in said velocity at a given position as compared to a baseline velocity; and c) treating said well to remove each added wax deposit.

[0049] A method of monitoring deposits on a wall of a well, said method comprising: a) cleaning a well of existing deposits sufficiently to allow a plunger from an instrumented plunger lift system to travel therethrough (unless said well is already sufficiently clean); b) obtaining a baseline of plunger velocity and position using said instrumented plunger lift system configured to record a baseline velocity and a position of said plunger as it travels through said well; c) monitoring said well at periodic intervals using said instrumented plunger lift system by recording a velocity and a position of said plunger as it travels through said well; d) using said baseline velocity and position from step b) and said recorded velocity and position step c) to determine a size and a position of an added deposit by a decrease in said recorded velocity in step c) as compared with said baseline velocity in step b) at a given position; and e) treating said well to remove each said added deposit when said added deposit slows said velocity.

[0050] A method of monitoring deposits on a wall of a well, said method comprising: a) cleaning a well of existing deposits sufficiently to allow a plunger from an instrumented plunger lift system to travel therethrough (unless said well is already sufficiently clean); b) obtaining a baseline of plunger velocity and position using said instrumented plunger lift system, said instrumented plunger lift system comprising a collar detector and a time counter and configured to record a baseline velocity and a position of said plunger as it travels through said well based on detecting each collar, a known distance between collars, and a time of travel between each collar; c) monitoring said well at periodic intervals using said instrumented plunger lift system by recording a velocity and a position of said plunger as it travels through said well; d) using said baseline velocity and position from step b) and said recorded velocity and position step c) to determine a size and a position of an added deposit by a decrease in said recorded velocity in step c) as compared with said baseline velocity in step b) at a given position; and e) treating said well to remove each said added deposit when said added deposit slows said velocity.

[0051] Any method herein described, wherein plunger velocity is measured during each drop to the bottom of the wellbore, or measured during plunger lift to the surface, or is measured throughout the drop-and-lift cycle.

[0052] Any method herein described, wherein plunger velocity is measured during each drop to the bottom of the wellbore, or measured during plunger lift to the surface, or is measured throughout the drop-and-lift cycle and production is occurring throughout said cycle. Thus, the plunger is both assisting with lift and being used to monitor deposit buildup at the same time.

[0053] Any method herein described, each said added deposit comprising one or more of wax, asphaltenes, or scale.

[0054] Any method herein described, further comprising treating said well to remove each said added deposit.

[0055] Any method herein described, further comprising obtaining said baseline velocity immediately after said cleaning step a).

[0056] Any method herein described, wherein said baseline velocity is determined between said added deposits.

[0057] Any method herein described, wherein said well is a vertical well in an oil reservoir or a heavy oil reservoir.

[0058] Any method herein described, wherein said plunger has a removable memory module, and said module is connected to a computer for said comparing step.

[0059] Any method herein described, wherein said plunger has a removable memory module, and said plunger is removed from said well at spaced intervals and said module is removed from said plunger and connected to a computer for said comparing step. Said intervals can be set according to the risk of buildup and be at weekly, monthly, or longer intervals. The intervals may also vary throughout the year e.g., as temperature drops in the winter, the intervals may be shortened.

[0060] Any method herein described, wherein said module communicates wirelessly throughout plunger operation or once each cycle.

[0061] Any method herein described, wherein said module is operably connected to contacts for direct data transfer to receiving contacts in the lubricator.

[0062] Any method herein described, wherein said treatment commences when said velocity in step c) is reduced at least 25% slower than said baseline velocity well b), preferably at least 20%, 15%, 10%, 5% or even more preferred at least 2%.

[0063] Any method herein described, wherein said well is a gas well, an oil well, a heavy oil well, or an extra heavy oil well.

[0064] Any method herein described, wherein oil, heavy oil, gas, or other hydrocarbon is produced from said well once deposits are removed or reduced.

[0065] As used herein a “wall” of a well includes the face of the wellbore, the tubing walls, and any other downhole wall surface subject to deposits.

[0066] As used herein, “providing” is intended to include use of existing equipment, as well as the provision of new equipment. Thus, providing a producing well can include using an existing well or drilling a new well, providing a smart plunger lift system can include using the existing system if outfitted with smart electronics or modifying a system to include the necessary equipment.

[0067] As used herein, “deposits” refers to buildup of any kind, including wax, asphaltenes, scale, and the like that form in crude oil production wells and equipment.

[0068] As used herein, “wax deposits” refers to the complex deposited mixture of wax, asphaltenes and other ingredients (but mainly waxes) that form in crude oil production wells and equipment.

[0069] As used herein, “plunger lift” is an artificial-lift method to produce fluids from wells by alternating well pressure to move the plunger from the distal to proximal end of a tubing string along with fluids and gases. In one embodiment, an automated system mounted on the wellhead controls the well on an intermittent flow regime. When the well is shut-in, a plunger is dropped down the production string. When the control system opens the well for production, the plunger and a column of fluid are carried up the tubing string. The surface receiving mechanism detects the plunger when it arrives at surface and, through the control system, prepares for the next cycle. In some instances, the plunger may be retained in a lubricator, in other cases the production valve may simply be shut removing the pressure differential allowing the plunger to drop back to the distal end of the well.

[0070] As used herein, “a plunger” means a device that allows plunger lift—it is the tubular, cylindrical, ball, or football shaped portion of the plunger lift system that travels up and down the well. A variety of plunger types are commercially available and include a ball and seat plunger, bar stock plunger, pad plunger, brush plunger, solid plunger, T-pad plunger, dual-T-pad plunger, retractable pad plunger, internal bypass plunger, rapid flow plunger, dual-continuous flow plunger, two-piece plunger, and other plunger configurations available from a variety of vendors, any of which may be used in the inventive methods herein described. Other components of the plunger lift system include a bottom hole bumper spring or other device that cushions the falling plunger. At the top of the system is a lubricator, plunger catcher, as well as piping, valving, sensors and controllers to handle various aspects of fluid flow. See also. FIG. 1 and description.

[0071] A “smart plunger” is equipped with one or more sensors that can measure temperature, pressure, depth, rate, collar detectors, velocity, and the like, as well as data recordation and transmission capabilities.

[0072] A “smart plunger system” includes the smart plunger, lubricator, catcher, bumper, sensors, valving, etc. plus any associated computers, processors, memory, control panels, communication systems, and the like for analyzing data and controlling the plunger.

[0073] The use of the word “a” or “an” in the claims or the specification means one or more than one, unless the context dictates otherwise.

[0074] 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.

[0075] 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.

[0076] 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, such as instructions for use, the opening and closing of various valves, equipment installation and removal, and the like.

[0077] Any claim or claim element introduced with the open transition term “comprising,” may also be narrowed to use the phrases “consisting essentially of” or “consisting of,” and vice versa. However, the entirety of claim language is not repeated verbatim in the interest of brevity herein.BRIEF DESCRIPTION OF THE DRAWINGS

[0078] FIG. 1. PRIOR ART shows the main components of a plunger lift system on an onshore well that is cased (see casing 109 and tubing 107). Subsurface components include a plunger 115 (here including a bypass valve 116), a bottomhole bumper spring 113, and an optional standing valve 111, which prevents fluids 117 from flowing out of the bottom of the tubing 107.

[0079] Surface components are attached to the wellhead 105 and include a motor valve 123 that has a controller 125 run via solar panel 127. A lubricator 101 and catcher assembly 103 accepts the plunger 115 as it rises through the wellhead 105, opening up a flow path for the produced gas to the flowline. An arrival catcher sensor 103 in catcher 104 detects the arrival of the plunger at the surface.

[0080] FIG. 2. PRIOR ART shows a conventional plunger lift cycle in panels 1-5. Panel 1—Gas production is at a maximum rate without liquid loading. Panel 2—Rate and flowing pressure decline naturally as liquid 217 accumulates in the tubing. Panel 3—After flowing pressure, flow rate or other trigger, the surface valve closes, and the plunger 215 drops (see arrow) through the gas and liquid. A bypass valve (if present) in the plunger enables efficient descent and closes when the plunger lands on the bottomhole bumper spring. Panel 4—The closed surface valve allows reservoir gas to accumulate and build up pressure in the casing-tubing annulus. Panel 5—The surface valve is then opened, allowing the pressurized annulus gas to push the plunger up the tubing, unloading the liquid (see hatching 217) via the flowline. The plunger is caught in the lubricator. Gas production restarts at maximum rate and the cycle begins again.

[0081] FIG. 3A-B PRIOR ART shows a smart plunger system (from U.S. Pat. No. 7,219,725).

[0082] FIG. 4 Flowchart for an ideal method of monitoring deposits.

[0083] FIG. 5 Flowchart for variant methods of monitoring deposits.

[0084] FIG. 6 Graph of I-plunger falling speed versus well depth, slowdowns showing the existence of deposits.DETAILED DESCRIPTION

[0085] The disclosure provides a novel method of monitoring buildup on the inner walls of a downhole well or tubing, and can be used in gas, oil, water and any vertical well system. The invention preferably uses a smart plunger lift system that is equipped with sensors, data recordation and transmittal features, and allows the user to determine plunger speed as it travels along the well. Since any deposits will slow the travel speed of the plunger, any time the plunger records a slowdown, that indicates the existence of a deposit on the inner wall of the well pipe.

[0086] An exemplary prior art smart plunger 305 is shown in FIG. 3A-B. Generally, instrumented plungers are very similar to the prior art plunger systems except there may be differences in the controller, and sensors, data recordation, and transmittal devices have been added thereto.

[0087] The exterior surface of the smart plunger typically includes a plurality of wiper ridges 310, or the surface of the plunger 305 can be of any suitable configuration known in the art including, but not limited to, a bristle brush section, and an expanding blade section.

[0088] A fish neck top section 315 is seen herein. In other variations the fish neck can be omitted. In one embodiment plunger comprises top and bottom sections 320 and 325 that are operatively coupled together to form a hollow interior 355 of the plunger in which one or more sensor assemblies 360 can be placed. As illustrated, the top section 320 includes a threaded male portion 335 and the bottom section 325 includes a corresponding female threaded portion 340 (or vice versa).

[0089] Wrench flats 330 can be provided on the bottom and / or top sections to facilitate the unscrewing of the sections. While the top and bottom sections are coupled using threaded portions in FIG. 3B, the two sections can also be coupled in other suitable manners, such as using one or more screw or bolts or corresponding keys and keyways on the respective sections.

[0090] The plunger includes an opening 345 at its bottom end 347 and various holes 350 extending from between the wiper ridges generally radially into the hollow interior compartment to permit oil, gas, water, and other fluids and gases to pass therethrough (not all plungers are hollow). Accordingly, the physical conditions, such as temperature and pressure, inside the plunger are essentially the same as the conditions immediately on the outside of the plunger. Openings to holes and ridges may be controllable dependent on the status of the plunger and if measurements are being taken. In other embodiments, they may be fixed.

[0091] One or more sensor assemblies 360 are positioned inside the plunger housings hollow interior 355. The sensor assemblies are typically configured to measure and record data relating to any number of conditions that may be useful to a well operator. For instance, sensor assemblies can be used that measure position, temperature, pressure, fluid-type, acceleration, load and velocity and can detect and / or count collars. Here, we need to measure plunger speed and location, so any sensor that accomplishes those goals could be used.

[0092] All the components must be capable of withstanding the elevated temperatures and pressures common in gas and oil wells not to mention the G-forces generated during the plunger's rapid deceleration. Coil springs 377 are placed on either end of the sensor assembly to cushion it from the shock of rapid deceleration as the plunger either is caught in a lubricator / catcher after its ascent, or it impacts a bumper in a well bottom after its descent.

[0093] The sensor assembly 360 is generally a self-contained unit. The assembly typically includes a sensor 365 adapted to measure a particular condition related to the well and / or the plunger. Suitable sensors adapted to the physical conditions of oil and gas wells are made by various manufactures, such as ENDEVCO, INC.®, MOTOROLA, INC®, DRUCK, INC.®, and HONEYWELL®, and are known in the art.

[0094] A data acquisition device 370 or controller is operatively coupled to the sensor 365. The data acquisition device may contain a processor 390 and may be operatively coupled to a memory module 380. Operationally, the data acquisition device typically drives the sensor to sample the conditions relating to the particular type of sensor on a periodic basis. The data acquisition device then receives the signal relating to a particular measurement and stores that data in the memory module.

[0095] A power supply 385, typically a battery, is operatively coupled to data acquisition device 370, the memory 380 and the sensor 365. The battery can be rechargeable, and a recharging mechanism (not shown) can be provided. In other embodiments, the battery is simply replaced, e.g., a lithium battery. In one variation, the recharging mechanism comprises an inducer that generates an electrical current in response to a pulsating magnetic field to recharge the battery. In another variation, a recharging interface simply comprises a set of electrical contacts situated on the surface of the plunger 305 that operatively couple with corresponding contacts located in the catch / lubricator.

[0096] In some embodiments of the sensor assembly 360, a data transfer device 395 is provided. In one variation, the data transfer device comprises a wireless transmitter that transmits data from the sensor assembly to a wireless receiver that is operatively coupled with the plunger lift system's controller. In another variation, the data transfer device can comprise a set of electrical contacts that are operatively coupled with the data acquisition device or the memory module that operatively couple with corresponding contacts in the lubricator / catcher to facilitate the transfer of data to the plunger lift system's controller and / or to recharge the plunger lift system's battery.

[0097] The wireless transmitter can operate on any suitable electromagnetic wavelength including commonly utilized radio frequencies, such as but not limited to 49 MHz, 900 MHz, 2.4 GHz, 5.8 GHz, the AM bands and the FM bands. It is to be appreciated that given the relatively low power of the battery-powered sensor assembly and the inability of most wireless devices to transmit through hundreds of feet of earth, a wireless connection between the plunger and an associated receiver can usually only be made when the plunger is above ground and within a short distance from the receiver. However, improvements in wireless technology may eventually make transmission of data along a substantial portion of the well's depth possible. Alternatively, acoustic signals may be transmitted in the wellbore, especially as this technology improves.

[0098] In one embodiment of the present invention, the wireless transmitter utilizes induction to transfer data between the sensor assembly and a wellhead / surface receiver. By sending pulsing current through an inductor comprising the data transfer device 395, a pulsating magnetic field is generated. By modulating one or all of the amplitude, phase and duration of the pulsing current, the data from the memory 380 is transmitted in the magnetic field. An electrical current is generated in the receiver, which also comprises an inductor, based on the variances in the magnetic field and the resulting pulsating current; a wellhead surface receiver can decipher the transferred data.

[0099] Where induction is used to both transfer data from the sensor assembly wirelessly and recharge the battery in the sensor assembly, the same inductor in the sensor assembly can be used to accomplish both tasks. In other embodiments two separate inductors can be used.

[0100] In other embodiments of the smart plunger 305 and sensor assembly 360, no recharging mechanism / interface is provided and no means for transferring the data directly to the controller is provided. Rather, the sensor assembly simply stores the data it gathers in memory 380 until the sensor assembly has been removed from the plunger and is hooked up to a computer by way of a USB, USB-C, lightening, micro-HDMI, HDMI, RF connector with or without threads, or other interface, for example, to download the data. The connector may have ingress protection, rubberized or protected connections that resist fluid and weather intrusion. While the sensor assembly is apart from the plunger the batteries can be either charged or replaced as well.

[0101] The I-PLUNGER™ from GOTEK™ uses USB to transfer data manually. While this particular type of plunger and sensor assembly combination does not necessarily facilitate real time data analysis and well operation parameter adjustment, it does provide for the capture of data concerning tubular, plunger, and reservoir conditions that was heretofore unavailable to well operators. A plunger with this type of sensor assembly can also be used in any type of well without modifying the plunger lift system controller.

[0102] Further, sensor assemblies that allow real time data collection are available off the shelf as they are currently used for wireline well logging. For instance, one such sensor is the SLIMLINE III™ pressure and temperature sensor made by CANADA TECH CORP™ of Calgary, Alberta.

[0103] In another embodiment, the plunger may be equipped with a wireless transmitter or contacts for data transfer in the lubricator depending upon the design and hardware used to transfer data between the plunger and the lubricator.

[0104] As yet another alternative, data may be stored in the plunger or sensor until the plunger returns to the near surface, and then wirelessly transmit that data with each cycle. In other embodiments, an instrumented tubing may transmit data through fiber optics or wired systems from the well bore to the surface depending upon the equipment used.

[0105] FIGS. 4 and 5 show flow charts for variations on the method.

[0106] In FIG. 4, the method begins by identifying an oil well with significant deposits 401. In step 403, this oil well is then cleaned of deposits, using any one or more of the methods described herein. The well should allow the smart plunger to freely fall in the well, thereby collecting baseline velocity and position data 405 each cycle. However, this step may be omitted if there are no significant deposits or if a new well. Note some variation in speed will occur if the well has any deviations from vertical, but the baseline data from a clean well will identify these.

[0107] Next the well is intermittently monitored 407 using the smart plunger and system, thereby recording velocity and position data at suitable time intervals. Each collected dataset is then compared against the baseline data 409 and that comparison will indicate the size and position of any added deposits 411 as determined from a reduction in speed from baseline as the deposits will slow down the plunger. Ideally the downward plunger velocity is used, but it may also be possible to use the upward velocity or both. In another embodiment, multiple cycles may be overlain or averaged to identify repeatable slowing, thus providing greater accuracy in identifying deposits.

[0108] FIG. 5 shows variations on the above idea, where the well is new or otherwise has no deposits 501 thus eliminating the cleaning step. Although obtaining a baseline data is ideal, it may be optional 505 and instead, one may use inter-deposit speed as the comparator 507 or use the monitoring data from an earlier run 509. The method is otherwise similar, and the comparison will serve to identify the estimated size and depth of the deposit 511.

[0109] For proof of concept, we let the GOTEK™ smart plunger fall in a well having a known paraffinic interval at about 1300 feet to 2800 ft in the Midland Basin play, and recorded falling velocity with depth. An on board collar locator provided plunger location and velocity as it travelled through the wellbore. Two runs were performed-one pretreatment and one post treatment. FIG. 6 shows actual plunger falling speed (velocity) versus well depth, slowdowns showing the existence of deposits. A change in velocity across the paraffinic interval (dashed vertical lines) is seen, indicating that the treatment improved the condition of the tubing. This confirms that the smart plunger can detect deposits and thus be used to monitor deposits downhole.

[0110] Although our test system used a smart plunger with a collar counter, collar counters are not essential herein. Depth may instead be inferred by knowing the total travel time, velocity over time, and location of the proximal and distal end of the tubing.

[0111] In another embodiment, the sensor system may be entirely automated, by providing a catch mechanism to receive data upon arrival in the lubricator or wirelessly transmitting data at the top of the cycle, data from the plunger can be transferred to surface equipment. Processors in the surface equipment will compare data collected over one or more trips to previous data. If repeated decreases in velocity are detected and fit the profile of scaling or wax buildup, the system may detect the buildup and treatment of the well can be initiated before damage or blockage occurs. Through proper and timely well treatment, damage to plungers and tubing can be prevented decreasing the number of costly workovers required over the life of the facility.

[0112] Further, with additional bench top experiments, we will be able to test plunger speed against deposits of known thickness, and use the data generated thereby to estimate the thickness of a deposit, since thicker deposits will slow the plunger more than thinner ones. In these experiments, we may test simulated deposits of varying hardness to ascertain the effect deposit hardness also has on speed-a soft wax predicted to impede velocity less than a very hard wax.

[0113] The present invention is exemplified with respect to the GOTEK™ smart plunger (aka I-PLUNGER™) and a heavy oil well in the Midland Basin play. However, this is exemplary only, and the invention can be broadly applied to any existing smart plunger, or one developed specifically for this purpose. The method can also be applied to any vertical well subject to deposits, scale, and the like.

[0114] The following references are incorporated by reference in their entirety.

[0115] U.S. Ser. No. 10 / 161,224 Hot water recycle for paraffin cleanout.

[0116] U.S. Ser. No. 11 / 427,749 Wax deposit removal using aqueous surfactant.

[0117] U.S. Pat. No. 7,219,725 Instrumented plunger for oil or gas well.

[0118] U.S. Ser. No. 12 / 097,538 Preventing fouling of crude oil equipment.

[0119] Sousa, A. L., et al. “Preventing and removing wax deposition inside vertical wells: a review.” J Petrol Explor. Prod. Technol. 9, 2091-2107 (2019), doi.org / 10.1007 / s13202-019-0609-x

[0120] Chen, X. T., et al., “Techniques for measuring wax thickness during single and multiphase flow.” Paper presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October (1997), doi: doi.org / 10.2118 / 38773-MS

[0121] Chen, X., et al., “Pressure-wave propagation technique for blockage detection in subsea flowlines.” Paper presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, U.S.A., November (2007), doi: doi.org / 10.2118 / 110570-MS

[0122] Chen, Y., et al., “Progress and perspectives of wax deposition in oil-gas systems: A review.” Chem. Eng. Res. Design, 208: 348-358 (2024), doi.org / 10.1016 / j.cherd.2024.06.033.

[0123] Franconi, N. G., et al., “Wireless communication in oil and gas wells.” Energy Technol 2(12):996-1005, (2014), doi.org / 10.1002 / ente.201402067

Claims

1. A method of reducing deposits in a downhole tubing, said method comprising:a) monitoring an addition of deposits in a vertical tubing using an instrumented plunger lift system comprising a plunger to record a velocity and depth of said plunger as it travels through said tubing;b) using said recorded velocity and depth to determine a size and a depth of each added deposit by a decrease in said velocity at a given depth as compared to a baseline velocity at said given depth; andc) treating said tubing to remove each said added deposit when each said added deposit slows said velocity.

2. The method claim 1, said method further comprising:first cleaning a tubing of existing deposits sufficiently to allow a plunger from an instrumented plunger lift system to travel therethrough (unless said tubing is already sufficiently clean).

3. The method of claim 1, said method comprising:obtaining a baseline of plunger velocity and depth using said instrumented plunger lift system, said instrumented plunger lift system configured to record a baseline velocity and depth of said plunger as it travels through said tubing; andcomparing said baseline velocity at a given depth and said recorded velocity at said given depth and position to determine a size and a position of an added deposit by a decrease in said recorded velocity as compared with said baseline velocity.

4. The method of claim 1, said method comprising:obtaining a baseline of plunger velocity and depth using said instrumented plunger lift system, said instrumented plunger lift system comprising a collar detector and a time counter and is configured to record a baseline velocity and depth of said plunger as it travels through said tubing based on detecting each collar, a known distance between collars, and a time of travel between each collar; andcomparing said baseline velocity at a given depth and said recorded velocity and said given depth to determine a size and a position of an added deposit by a decrease in said recorded velocity as compared with said baseline velocity.

5. The method of claim 1, further comprising treating said tubing to remove said added deposit.

6. The method of claim 5, wherein said treating commences when said velocity is reduced at least 10%.

7. The method of claim 1, wherein said added deposit comprising one or more of wax, asphaltenes, or scale.

8. The method of claim 2, further comprising obtaining said baseline velocity immediately after said cleaning.

9. The method of claim 1, wherein said baseline velocity is determined between said added deposits.

10. The method of claim 1, wherein said tubing is a vertical section of a tubing in a hydrocarbon reservoir selected from a gas reservoir, condensate reservoir, oil reservoir, shale reservoir, and a heavy oil reservoir.

11. The method of claim 1, wherein said tubing is a vertical section in a horizontal well.

12. The method of claim 1, wherein said plunger has a collar counter.

13. The method of claim 1, wherein said plunger has a velocity recorder.

14. The method of claim 1, wherein said plunger has a removable memory module, and said module is removed and connected to a computer for said comparing step.

15. A method of monitoring and cleaning deposits on a wall of a tubing in a well, said method comprising:a) cleaning a tubing in a well of existing deposits sufficiently to allow a plunger from an instrumented plunger lift system to travel therethrough (unless said tubing is already sufficiently clean);b) obtaining a baseline of plunger velocity with depth using said instrumented plunger lift system, said instrumented plunger lift system configured to record a baseline velocity with depth of said plunger as it travels through said tubing;c) monitoring said tubing at periodic intervals using said instrumented plunger lift system by recording a monitored velocity with depth of said plunger as it travels through said tubing;d) comparing said baseline velocity with depth from step b) and said monitored velocity with depth in step c) to determine a size and a position of an added deposit by a decrease in said recorded velocity in step c) as compared with said baseline velocity in step b) at a given depth; ande) treating said tubing to remove each said added deposit when said added deposit slows said velocity.

16. The method of claim 15, wherein said plunger has a removable memory module, and said module is removed from said plunger and connected to a computer for said comparing step.

17. The method of claim 15, wherein said plunger comprises a memory module operably connected to a wireless communication system, and said memory module wirelessly connects to a computer for said comparing step.

18. The method of claim 15, wherein said plunger comprises a memory module operably connected to a wireless communication system, and said module wirelessly connects to a computer for said comparing step when said plunger returns to a surface of said reservoir in each lift cycle.

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