Patent Application
20060011345
1. Field of the Invention
This invention relates to oil and gas well production technology. More particularly, it relates to the in situ treatment of fluids produced by an artificial lift oil well to inhibit the formation of scale inside and outside of production tubing, pumps, valves, and the like and to reduce the amount of solids that enter the pump.
2. Description of the Related Art
A typical oil well produces not only oil, but also gas and water, often in significant quantity. The fluids often transport solids, such as sand, as well as other potentially damaging fluids and gases, from the reservoir into the production tubing and casing, and up the production tubing to the surface. Equipment on the surface may be used to separate these production components. The oil is recovered; the gas, depending on its composition, may be filtered, treated and piped to a collection facility or flared off; the water may be re-injected into another formation or, in the case of offshore production platforms, treated to prevent environmental contamination and then discharged overboard; and the solids are separated and disposed of.
The oil and water produced by oil and gas wells often contains significant quantities of dissolved minerals. Frequently, the water is saturated with these minerals—i.e., the water contains the maximum concentration of the dissolved minerals possible at a given temperature and pressure. Changes in temperature and/or pressure which occur as the fluid is pumped from the production zone through the well to the treatment equipment on the surface can cause the minerals to come out of solution (“precipitate”) and become deposited on the interior and exterior surfaces of the production tubing, pumps, valves, chokes and other equipment. The deposit is known as “scale” and it can significantly reduce the diameter and hence the capacity of production tubing. In extreme cases, the pipe or tubing can become completely obstructed, shutting down production. Even in less severe cases, where the fluid is not saturated, scale can build up on the interior and exterior of any exposed surface.
Certain dissolved minerals in water are known as “hardness ions”—divalent cations that include calcium (Ca+2), magnesium (Mg+2) and ferrous (Fe+2) ions. Hardness ions develop from dissolved minerals, bicarbonate, carbonate, sulfate and chloride. Heating water containing bicarbonate salts can cause the precipitation of a calcium carbonate solid. Raising the pH can allow the Mg+2 and Fe+2 ions to precipitate as Fe(OH)2 and Mg(OH)2. Excess sodium carbonate can precipitate Ca+2 as CaCO3.
Precipitation is the formation of an insoluble material in a solution. Precipitation may occur by a chemical reaction of two or more ions in solution or by changing the temperature of a saturated solution. There are many examples of this important phenomenon in drilling fluids. Precipitation occurs in the reaction between calcium cations and carbonate anions to form insoluble calcium carbonate: Ca+2+CO3−2→CaCO3.
Scale is a mineral salt deposit or coating formed on the surface of metal, rock or other material. Scale may be caused by a precipitation resulting from a chemical reaction with the surface on which it forms, precipitation caused by chemical reactions, a change in pressure or temperature, or a change in the composition of a solution. The term “scale” is also applied to a corrosion product. Typical scales are calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, the various silicates and phosphates and oxides, or any of a number of compounds insoluble or slightly soluble in water.
Scale may be deposited on wellbore tubulars, down hole equipment, and related components as the saturation of produced water is affected by changing temperature and pressure conditions in the production conduit. In severe conditions, scale creates a significant restriction, or even a plug, in the production tubing. Scale build-up in the artificial lift pump can lead to failure of the pump due to blocked flow passages and broken shafts. Scale removal is a common well-intervention operation. A wide range of mechanical, chemical and scale inhibitor treatment options are available to effect scale removal.
Scale can also occur in tubing, the gravel pack, the perforations or the formation itself Scale deposition occurs when the solution equilibrium of the water is disturbed by pressure and temperature changes, dissolved gases or incompatibility between mixing waters. Scale deposits are the most common and most troublesome damage problems in the oil field and can occur in both production and injection wells.
All waters used in well operations can be potential sources of scale, including water used in waterflood operations and filtrate from completion, workover or treating fluids. Therefore, reduction of scale deposition is directly related to reducing the amount of bad water that is produced.
Carbonate scale is usually granular and sometimes very porous. A carbonate scale can be easily identified by dropping it in a solution of hydrochloric acid where bubbles of carbon dioxide will be observed effervescing from the surface of the scale. Sulphate scales are harder and more dense. A sulphate deposit is brittle and does not effervesce when dropped in acid. Silica scales resemble porcelain—they are very brittle, not soluble in acid, but dissolve slowly in alkali.
Scale removal is a common well-intervention operation involving a wide variety of mechanical scale-inhibitor treatments and chemical options. Mechanical removal may be done by means of a pig or by abrasive jetting that cuts scale but leaves the tubing intact. Scale-inhibition treatments involve squeezing a chemical inhibitor into a water-producing zone for subsequent commingling with produced fluids, preventing further scale precipitation. Chemical removal is performed with different solvents according to the type of scale:
Calcium scales such as calcium sulfate, calcium carbonate and calcium oxalate are insoluble in water. However, all three are soluble in a Sodium Bisulfate acid solution. Calcium scale can be removed with an acid wash using a 5-15% solution of Sodium Bisulfate (SBS). SBS can also be used during a shut down to remove scale by re-circulating it throughout areas of the process where needed. The concentration of SBS solutions and the re-circulation time depend on the amount of scale that needs to be removed. SBS can be a substitute for sulfamic acid in calcium scale removal situations.
Zinc sulfide (ZnS) is another one of the oil field scales that plagues production. Although it does not seem to be common, according to field experience and published literature, it causes a significant flow/production problem when it does occur, just as all other scales adversely affect wells. Other scales, such as barium sulfate and strontium sulfate, also cause production problems but are much harder than ZnS.
Although chemical solvents have been used on these harder scales, the results are often disappointing. While mechanical scale removal has been used successfully on barium and strontium sulfate scales with excellent success, it had not been used on ZnS scale. It was conceivable that the softer scale may not respond to the same process that removed harder scales.
In certain cases, scale may be an environmental or health hazard. The State of Louisiana, Department of Environmental Quality has issued a notification concerning a potential health hazard associated with handling pipe used in oil and gas production that may be contaminated with radioactive scale from naturally-occurring radioactive materials (NORM). The concern is the possible inhalation and/or ingestion of scale particles contaminated with radium-226 and possibly other radioactive material that may become airborne during welding, cutting or reaming pipe that contains radioactive scale. The State of Louisiana is using the term Technologically Enhanced Natural Radiation (TENR) for this material that is a subset of the NORM group.
An inhibitor is a chemical agent added to a fluid system to retard or prevent an undesirable reaction that occurs within the fluid or with the materials present in the surrounding environment. A range of inhibitors is commonly used in the production and servicing of oil and gas wells, such as corrosion inhibitors used in acidizing treatments to prevent damage to wellbore components and inhibitors used during production to control the effect of hydrogen sulfide [H2S]
A scale inhibitor is a chemical agent added to a fluid system to retard or prevent an undesirable reaction that occurs within the fluid or with the materials present in the surrounding environment. A range of inhibitors is commonly used in the production and servicing of oil and gas wells, such as corrosion inhibitors used in acidizing treatments to prevent damage to wellbore components and inhibitors used during production to control the effect of hydrogen sulfide [H2S]
A sequestering agent (or chelation agent) is a chemical whose molecular structure can envelop and hold a certain type of ion in a stable and soluble complex. Divalent cations, such as hardness ions, form stable and soluble complex structures with several types of sequestering chemicals. When held inside the complex, the ions have a limited ability to react with other ions, clays or polymers. Ethylenediamine tetraacetic acid (EDTA) is a well-known sequestering agent for the hardness ions, such as Ca+2, and is the reagent solution used in the hardness test protocol published by API. Polyphosphates can also sequester hardness ions. Sequestering is not the same as precipitation because sequestering does not form a solid. For calcium carbonate deposits, glycolic and citric acids and ammonium salts and blends incorporating EDTA are used as chelants.
A scale-inhibitor squeeze is a type of inhibition treatment used to control or prevent scale deposition. In a scale-inhibitor squeeze, the inhibitor is pumped into a water-producing zone. The inhibitor is attached to the formation matrix by chemical adsorption or by temperature-activated precipitation and returns with the produced fluid at sufficiently high concentrations to avoid scale precipitation. Some chemicals used in scale-inhibitor squeezes are phosphonated carboxylic acids or various polymers.
Some scale-inhibitor systems integrate scale inhibitors and fracture treatments into one step, which guarantees that the entire well is treated with scale inhibitor. In this type of treatment, a high-efficiency scale inhibitor is pumped into the matrix surrounding the fracture face during leakoff. It adsorbs to the matrix during pumping until the fracture begins to produce water. As water passes through the inhibitor-adsorbed zone, it dissolves sufficient inhibitor to prevent scale deposition. The inhibitor is better placed than in a conventional scale-inhibitor squeeze, which reduces the re-treatment cost and improves production.
Some well treatment systems continuously inject the treating chemical in the well using a metering pump. The chemicals are either injected below the pump using a capillary line or injected into the well annulus. When chemicals are injected into the well annulus the chemicals build up in the well bore until the pump pulls them down the wellbore and into the pump intake.
Due to the time that it takes for the chemicals to reach the pump, changes in chemical mix or injection rates are very slow to affect the fluids entering the pump. If the pump intake is above the electric motor in an Electric Submersible Pump, ESP installation, the chemicals do not protect the motor or the casing below the pump intake.
In capillary injection systems, the location of the chemical injection can be determined when the system is installed by terminating the capillary tube below the pump intake/motor combination in an ESP completion. The capillary injection tube provides continuous treatment of the fluids and the time delay for adjustments to the blend of chemicals and/or treatment rate can be minimized.
Sand produced with the fluids can cause damage to pumping systems. Abrasion resistant pumps with engineered ceramic bearings and coated flow passages have been developed to improve pump life in wells that produce sand, but sand will eventually wear out even these special sand-tolerant pumps.
One practice for removing sand from the fluid is by installing a liquid and sand separator between the casing perforations and the pump intake. These systems deposit the separated sand into the well's rat hole or into tubing hung from the bottom of the separator as a trap. Wilson discloses a means for removal of sand separated with a downhole sand separator in U.S. Pat. No. 6,216,788.
Gravel packing is a sand-control method used to prevent the production of formation sand. It involves the placement of selected gravel across the production interval to prevent the production of formation fines or sand. Any gap or interruption in the pack coverage may permit undesirable sand or fines to enter the producing system.
In gravel pack operations, a steel screen is placed in the wellbore and the surrounding annulus is then packed with prepared gravel of a specific size that is designed to prevent the passage of formation sand. The primary objective is to stabilize the formation while causing minimal impairment to well productivity.
Wire-wrapped screen is one type of screen used in sand control applications to support the gravel pack. The profiled wire is wrapped and welded in place on a perforated liner. Wire-wrapped screen is available in a range of sizes and specifications, including outside diameter, material type and the geometry and dimension of the screen slots. The space between each wire wrap must be small enough to retain the gravel placed behind the screen, yet minimize any restriction of production.
A sand filter as described by Stanley in U.S. Pat. No. 4,977,958 is used to filter the sand out of the fluid prior to entering the pump intake. This style of intake filter has been installed in numerous wells and is effective for removal of solids, but once the filter is full of sand, fluid flow through the filter is restricted and a large pressure drop occurs. As the pressure drop increases, the rate of sand accumulation increases causing the rate of pressure drop to increase until eventually the fluid flow across the filter ceases. When fluid flow to the pump ceases, the pump will cavitate and eventually fail.
A fluid conditioning system is installed between the well perforations and the intake of a pump used to effect artificial lift. The fluid conditioning system is an apparatus that provides scale inhibitors and/or other chemical treatments into the production stream. The production stream may also be filtered by the apparatus prior to the production stream's introduction into the pump. In some embodiments, the fluid conditioning system may be a part of the production stream filter wherein the filtering material is comprised of a porous medium that contains and supports the treatment chemical. In other embodiments, the chemical treatment may be accomplished by the gradual dissolution of the unsupported solid phase chemical itself The treating chemical may be recharged or replenished by various downhole reservoirs or feeding means. In yet other embodiments, the chemical treatment may be replenished from the surface by means of a capillary tube. In certain other embodiments, the apparatus may be retrievable from the surface by means of a wireline or coil tubing thereby permitting recharge or replenishment of the chemical in the apparatus on an as-needed or periodic basis. The filtration apparatus may incorporate a by-pass valve that allows fluid to by-pass the filter as sand or other particulate matter fills up or blocks the filter.
Advances in electric motor technology have made Electric Submersible Pumps (ESPs) an increasingly popular method of providing artificial lift for oil wells. Operating in the harsh conditions of the downhole environment, an ESP must be protected from ingesting corrosive, abrasive, or any other detrimental substance in the production fluids in order to provide a Mean Time Between Failure (MTBF) that justifies its use on an economic basis. In addition, treating the production fluids while downhole minimizes the potential hazards involved in bringing the production fluids to the surface while the production fluids may contain any detrimental substance. Moreover, scale build-up in production tubing and pump chambers must also be controlled in order to decrease the number of well interventions or workovers needed during the useful life of an oil well.
The present invention is a novel apparatus and method which combines the functions of preventing fines or sand from entering the pump with the introduction of a scale inhibitor or other chemical treatments into the production stream prior to entering the pump. In an alternative embodiment the production stream may be treated for environmental hazards after entering the pump.
Referring now to
Filter assembly 16 comprises top plate 18 and bottom plate 20. Top plate 18 allows internal tubular 24 to pass through its center portion and may be joined to inlet connector 14 in a fluid tight manner. Top plate 18 and bottom plate 20 are connected by an external tubular 22 and by an internal tubular 24. The external tubular 22 may be a screen or other type of porous structure that allows a desired wellbore fluid to pass from one side of the tubular to the other while restraining the passage of undesired wellbore fluids or solids. The internal tubular 24 may be a screen or other type of porous structure that allows a desired wellbore fluid to pass from one side of the tubular to the other while restraining the passage of undesired wellbore fluids or solids. Together, external tubular 22 and internal tubular 24 define annular space 32 which may be used to contain medium 30 [partially shown in
Should the filter assembly 16 become at least partially clogged with solid or other matter that may be present in the wellbore such that wellbore fluid can no longer pass through the filter assembly 16 and reach the artificial lift system 10 then the artificial lift system 10 may be severely damaged. Such damage may result from such causes as pump cavitation. In cases where the wellbore fluid is used to cool the artificial lift system's motor, a partially clogged filter assembly may reduce the flow of cooling wellbore fluid to the extent that motor overheating may also occur. In order to prevent such damage to the artificial lift system, a by-pass valve 132 may be installed. Typically, although not always, the bottom plate 20 may have an opening through its center that allows fluid to pass directly from the well-bore into the central passage 28 of the internal tubular 24. A by-pass valve 132 is located in the opening through the bottom plate 20. The by-pass valve 132 may be a ball valve, a spring-loaded valve, a poppet valve, a shear assembly, rupture disc, or any other type of valve that may be activated to relieve differential pressure. In some embodiments when the pressure drop across the screen equals the by-pass setting, the by-pass valve 132 partially opens and wellbore fluid is allowed to by-pass the filter assembly 16. As fluid by-passes the filter assembly 16, the flow rate through the filter is reduced; thus, the pressure drop is reduced for the matter-packed filter. With the by-pass valve 132 partially open, a portion of the wellbore fluid flows into the central passage 28 through the filter assembly and a portion flows into the central passage 28 through the by-pass valve 132. The proportions of wellbore fluid that pass through the filter assembly 16 and the by-pass valve 132 can be represented by Q (total flow)=Qf (flow through filter assembly)+Qb (by-pass flow). As time passes, Qf will be reduced as more wellbore matter packs into the filter assembly 16 and the P (pressure) drop increases for a given flow rate thus causing Qb to increase. A typical flow curve is illustrated in
External tubular 22 may be any porous material with sufficient corrosion resistance and structural strength to withstand the torque, well obstructions, tension loading, compression loading, pressure differentials or any other conditions that may be encountered during insertion in the production casing and operation of the artificial lift system. In certain embodiments, external tubular 22 may be a wire mesh screen. In other embodiments, external tubular 22 may be a wire-wound screen. Stainless steels are a particularly preferred screen material owing to their mechanical strength and corrosion resistance. The screen may comprise a mechanical support for providing structural integrity. The screen may be selected to provide the desired opening size to exclude the sand and/or fines encountered in a particular well environment.
Internal tubular 24 may also be a screen or, in other embodiments, may comprise a pipe having openings or perforations 26. Openings 26 may also be size-selected for a particular application. Openings 26 may comprise holes or slots in the wall of internal tubular 24. Internal tubular 24 defines central passage 28 that is in fluid communication with inlet connector 14 of pump 100.
Annular space 32 may be occupied by medium 30 which may be a porous medium such as pumice—a highly-porous igneous rock, usually containing 67 to 75% SiO2 and 10 to 20% Al203. Potassium, sodium and calcium are generally present. Pumice has a glassy texture. It is insoluble in water and not attacked by acids. It is commercially available in lump or powdered form (coarse, medium and fine).
Medium 30, when impregnated with a chemical agent, may be used to perform at least two functions: 1) mechanical filtration; and, 2) treatment of the fluid(s) flowing into the inlet of pump 100 with the chemical agent. The mechanical filtration function excludes sand, fines, and other wellbore matter, including highly viscous fluids that are not blocked by external tubular 22. The extent of this mechanical filtration is determined, at least in part, by the particle size and packing density of medium 30. Accordingly, the composition of medium 30, its particle size and its loading within annular space 32 may be optimized for various well conditions.
The size and configuration of openings 26 in internal tubular 24 may be optimally chosen to exclude medium 30 while providing the minimum restriction to flow of the production fluids. Alternatively, the size and configuration of openings 26 in internal tubular 24 may be chosen to provide another level of wellbore fluid filtration, where even smaller particles of matter are excluded from the central passage 28.
Top plate 18 and/or bottom plate 20 may be removable to facilitate charging filter assembly with medium 30.
In some embodiments, medium 30 may be the chemical agent in a solid form that slowly dissolves in the production fluids. In such embodiments, the physical filtering function of medium 30 dissipates over time and hence external tubular 22 and internal tubular 24 should be selected to provide sufficient sand, fines, or other matter exclusion to adequately protect pump 100.
Referring now to
Filter assembly 116 comprises top plate 18 and bottom plate 20. Top plate 18 allows internal tubular 24 to pass through its center portion and may be joined to inlet connector 14 in a fluid tight manner. Top plate 18 and bottom plate 20 are connected by an external tubular 22 and by an internal tubular 24. The external tubular 22 may be a screen or other type of porous structure that allows a desired wellbore fluid to pass from one side of the tubular to the other while restraining the passage of undesired wellbore fluids or solids. The internal tubular 24 may be a screen or other type of porous structure that allows a desired wellbore fluid to pass from one side of the tubular to the other while restraining the passage of undesired wellbore fluids or solids. Additionally, shown in
Should the filter assembly 116 (including any intermediate tubulars or media contained in the additional annular spaces created by the intermediate tubulars) become at least partially clogged with solid or other matter that may be present in the wellbore such that wellbore fluid can no longer pass through the filter assembly 116 and reach the artificial lift system 10, the artificial lift system 10 may be severely damaged. Such damage may result from pump cavitation. In cases where the wellbore fluid is used to cool the artificial lift system's motor a partially clogged filter assembly may reduce the flow of cooling wellbore fluid to the point where motor overheating may also occur. In order to prevent such damage to the pump, motor or drive system a by-pass valve 134 may be installed. Typically, although not always, in the bottom plate 20. The by-pass valve 134 may be a ball valve, a spring-loaded valve, a poppet valve, a shear assembly, or any other type of valve that may be activated if a sufficient differential pressure is determined to exist. When the pressure drop across the screen equals the by-pass setting, the by-pass valve 134 partially opens and wellbore fluid is allowed to by-pass the filter assembly 116. As fluid by-passes the filter assembly 116, the flow rate through the filter is reduced; thus, the pressure drop is reduced for the sand-packed filter. With the by-pass valve 134 partially open, a portion of the wellbore fluid is flowing into the central passage 28 through the filter assembly and a portion is flowing into the central passage 28 through the by-pass valve 134. The proportions of wellbore fluid that are passing through the filter assembly 116 and the by-pass valve 134 can be represented by Q (total flow)=Qf (flow through filter assembly)+Qb (by-pass flow). As time passes, Qf will be reduced as more wellbore matter packs into the filter assembly 116 and the P (pressure) drop increases for a given flow rate thus causing Qb to increase. A typical flow curve is illustrated in
External tubular 22 may be any porous material, including metals, composites or plastics with sufficient corrosion resistance and structural strength to withstand the torque, well obstructions, tension loading, compression loading, pressure differentials or any other conditions that may be encountered during insertion in the production casing and operation of the artificial lift system. In certain embodiments, external tubular 22 may be a wire mesh screen. In other embodiments, external tubular 22 may be a wire-wound screen. Stainless steels are a particularly preferred screen material owing to their mechanical strength and corrosion resistance. The screen may comprise a mechanical support for providing structural integrity. The screen may be selected to provide the desired opening size to exclude the sand and/or fines encountered in a particular well environment.
The at least one intermediate tubulars 25 and internal tubular 24 may also be a screen or, in other embodiments, may comprise a pipe having openings or perforations 26. Openings 26 may also be size-selected for a particular application. Openings 26 may comprise holes or slots in the wall of internal tubular 24. Internal tubular 24 defines at least one central passage 28 that is in fluid communication with inlet connector 14 of pump 100.
The at least two annular spaces 32 and 33 may be occupied by the at least two media 30 and 31 which may be a porous medium such as pumice—a highly-porous igneous rock, usually containing 67 to 75% SiO2 and 10 to 20% Al2O3. Potassium, sodium and calcium are generally present. Pumice has a glassy texture. It is insoluble in water and not attacked by acids. It is commercially available in lump or powdered form (coarse, medium and fine).
Media 30 and 31, when impregnated with a chemical agent, may be used to perform at least two functions: 1) mechanical filtration; and, 2) treatment of the fluid(s) flowing into the inlet of pump 100 with the chemical agent. The mechanical filtration function excludes sand and fines that are not blocked by external tubular 22. The extent of this mechanical filtration is determined, at least in part, by the particle size and packing density of the media 30 and 31. Accordingly, the composition of media 30 and 31, its particle size and its loading within the annular spaces 32 and 33 may be optimized for various well conditions.
The size and configuration of the openings in the intermediate tubulars 25 and in internal tubular 24 may be optimally chosen to exclude the media 30 and 31 while providing the minimum restriction to flow of the production fluids.
Top plate 18 and/or bottom plate 20 may be removable to facilitate charging filter assembly with at least media 30 and 31.
In some embodiments, media 30 and 31 may be chemical agents in a solid form that slowly dissolves in the production fluids. In such embodiments, the physical filtering function of the media 30 and 31 dissipates over time and hence external tubular 22 and internal tubular 24 should be selected to provide sufficient sand and/or fines exclusion to adequately protect pump 100.
Additional downhole components may be included in order to facilitate the use and recovery of the apparatus. The embodiment of the invention shown in
One preferred scale inhibitor is phosphoric acid (also known as orthophosphoric acid), a colorless, odorless liquid or transparent, crystalline solid, depending on concentration and temperature. The pure acid (100% strength) is in the form of crystals that melt at about 42° C. and lose ½ mole of water at 213° C. to form pyrophosphoric acid.
The scale inhibitor may be a phosphate salt—a group of salts formed by neutralization of phosphorous or phosphoric acid with a base, such as NaOH or KOH. Orthophosphates are phosphoric acid (H3PO4) salts, where 1, 2 or 3 of the hydrogen ions are neutralized. Neutralization with NaOH gives three sodium orthophosphates: (a) monosodium phosphate (MSP), (b) disodium phosphate (DSP) or (c) trisodium phosphate (TSP). Their solutions are buffers in the 4.6 to 12 pH range. All will precipitate hardness ions such as calcium.
By utilizing this method the wellbore fluid may be treated downhole with other chemicals as well including inhibitors such as corrosion inhibitors, emulsion breakers, surfactants, chemicals to prevent the deposition of paraffin, hydrogen sulfide scavengers.
It will be appreciated by those skilled in the art that each chemical agent in media 30 and/or 31 will become depleted in use as production fluids flow over media 30 and/or 31 dissolving or desorbing the chemical agent. If the chemical agent is a liquid at the temperatures and pressures existing in the downhole environment, filter assembly 116 may be equipped with a capillary tube recharge means as illustrated in
As shown in the transverse, cross-sectional view of
If the chemical agent is a solid-phase material that dissolves in the production fluid(s), downhole replenishment of the chemical agent supply may be accomplished with the apparatus shown in longitudinal cross section in
In this way, the useful life of the filter assembly with the treating chemicals may be extended. Since oil and gas wells may be thousands of feet deep, there is typically ample volume in the annular space between the production casing and the production tubing to accommodate an extension 40 of significant capacity. The length of extension 40 is limited only by the availability of annular space between the production tubing and the casing. In alternative embodiments the extension 40 or even a separate hopper assembly [not shown] could be refilled by using a capillary or feed tube system. In another embodiment the extension 40 could be attached to the filter assembly as a separate hopper that could be refilled by retrieving the hopper. One means for retrieving the hopper could be by using a wireline.
If the chemical agent is a liquid-phase material, a downhole reservoir of the agent may be provided and utilized by means of the apparatus shown in longitudinal cross section in
In some instances, gas that may be present in the wellbore fluid may damage the artificial lift system 230 by causing the pump to cavitate, run at excessive speed, or repeatedly load and unload the artificial lift system. The embodiment depicted in
Yet another embodiment of the invention is shown in longitudinal cross section in
While the present invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention.
