BACKGROUND 
   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 CaCO 3 . 
   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 +CO 3   −2 →CaCO 3 . 
   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:
         Carbonate scales such as calcium carbonate or calcite [CaCO 3 ] can be readily dissolved with hydrochloric acid [HCl] at temperatures less than 250° F. [121° C.].   Sulfate scales such as gypsum [CaSO 4 .2H 2 O] or anhydrite [CaSO 4 ] can be readily dissolved using ethylenediamine tetraacetic acid (EDTA). The dissolution of barytine [BaSO 4 ] or strontianite [SrSO 4 ] is much more difficult.   Chloride scales such as sodium chloride [NaCl] are easily dissolved with fresh water or weak acidic solutions, including HCl or acetic acid.   Iron scales such as iron sulfide [FeS] or iron oxide [Fe 2 O 3 ] can be dissolved using HCl with sequestering or reducing agents to avoid precipitation of by-products, for example iron hydroxides and elemental sulfur.   Silica scales such as crystallized deposits of chalcedony or amorphous opal normally associated with steamflood projects can be dissolved with hydrofluoric acid [HF].       

   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 [H 2 S] 
   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 [H 2 S] 
   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&#39;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. 
   SUMMARY OF THE INVENTION 
   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&#39;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. 


   
     BRIEF DESCRIPTION OF THE DRAWING FIGURES 
       FIG. 1  is a cross-sectional view of an artificial lift pump equipped with an intake screen having a single-layer treatment space. 
       FIG. 2  is a typical flow curve for a by-pass valve. 
       FIG. 3  is a cross-sectional view of an artificial lift pump equipped with an intake screen having at least two annular treatment spaces. 
       FIG. 4  depicts the apparatus of  FIG. 3  additionally equipped with a packer, shear sub and cross-over sub. 
       FIG. 5  is a cross-sectional view of the intake screen portion of the apparatus shown in  FIG. 4  taken along line V—V. 
       FIG. 6  is a cross-sectional view of an artificial lift pump equipped with a multiple layer intake screen having capillary tube recharge means. 
       FIG. 7  is an alternative embodiment of the apparatus shown in  FIG. 6  which includes means for distributed recharge of the treatment chemicals. 
       FIG. 8  is a cross-sectional view of an artificial lift pump equipped with a dual-layer intake screen equipped with a downhole replenishment means for solid-phase chemicals. 
       FIG. 9  is an alternative embodiment of the apparatus shown in  FIG. 8  which has means downhole replenishment of both solid-phase and liquid-phase chemicals. 
       FIG. 10  is a cross-sectional view of an artificial lift pump that has a dual-layer intake screen equipped with a downhole replenishment means for liquid-phase chemicals. 
       FIG. 11  is a cross-sectional view of an alternative embodiment of the apparatus shown in  FIG. 10 . 
       FIGS. 12A and 12B  are cross-sectional views of production tubing having capillary tubing incorporated within their wall structure. 
       FIG. 13  is a cross-sectional view of an artificial lift pump equipped with a wireline (or slickline) retrievable, chemical treatment intake screen. 
       FIG. 14  is an alternative embodiment of the apparatus shown in  FIG. 13  that further comprises an extension of the shroud around the pump and intake sections. 
       FIG. 15  is a cross-sectional view of a shaft-driven artificial lift pump equipped with a chemical treatment intake screen situated between the pump and its driving motor. 
       FIG. 16  is a cross-sectional view of an alternative embodiment of the apparatus of  FIG. 15  wherein the screen is located within the interior portion of the intake filter. 
   


   DETAILED DESCRIPTION OF THE INVENTION 
   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  FIG. 1 , artificial lift system  10  includes pump  100  attached at its outlet end to production tubing  12  and at its inlet to inlet connector  14  which is in fluid communication with filter assembly  16 . Filter assembly  16  is preferably designed such that wellbore fluid will pass from the exterior  21  of external tubular  22  through external tubular  22  through any medium  30  through internal tubular  24  and into the central passage  28  of internal tubular  24 . Artificial lift system  10  may be generally circular in cross section and sized to fit within the production casing of a well [not shown]. In some embodiments, pump  100  may be an ESP that receives electrical power from the surface via an electrical cable within the well bore [not shown]. 
   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  FIG. 1  for clarity]. 
   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&#39;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  FIG. 2 . As the pressure drop across the filter assembly  16  increases, a larger fraction of the total flow passes through the bypass valve  132 . Those skilled in the art will appreciate that different bypass valve designs will exhibit different flow curves. In an alternative embodiment, where a by-pass valve  132  is provided, the by-pass valve  132  could open just prior to the point at which wellbore fluid flow is reduced to the level that damage to the artificial lift system is predicted to occur. In addition, activation of the bypass valve should alert the operator on the surface that the filter assembly  16  might require service. Such service may be in the form of removal of the entire artificial lift system and filter assembly, reverse operation of the artificial lift system, or back-flushing fluid through the system from the surface so as to force out matter that may have accumulated in the filter assembly. 
   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% 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). 
   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  FIG. 3 , artificial lift system  10  includes pump  100  attached at its outlet end to production tubing  12  and at its inlet to inlet connector  14  which is in fluid communication with filter assembly  116 . Filter assembly  116  includes one or more intermediate tubulars  25  [only a single intermediate tubular is shown for clarity] and thus filter assembly  116  has at least two annular spaces,  32  and  33 . It will be appreciated by those skilled in the art that multiple intermediate walls may be incorporated into filter assembly  116  and thus multiple annular spaces may be defined within the apparatus. Each annular space may be used to contain a different medium to provide various functions—e.g., graduated mechanical filtration and/or treatment with different chemical agents. Intermediate wall  25  may comprise a screen, perforated tubular, or other type of porous material. The screen mesh or perforation size may be selected to substantially prevent medium  30  from entering annular space  32 . Filter assembly  116  is preferably designed such that wellbore fluid will pass from the exterior  21  of external tubular  22  through external tubular  22  through any medium  30  through any intermediate tubulars  25  through any additional medium  31  through internal tubular  24  and into the central passage  28  of internal tubular  24 . Artificial lift system  10  may be generally circular in cross section and sized to fit within the production casing of a well [not shown]. In some embodiments, pump  100  may be an ESP that receives electrical power from the surface via an electrical cable within the well bore [not shown]. 
   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  FIG. 3 , there may be one or more intermediate tubulars  25  that may also comprise 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 , intermediate tubular  25 , and internal tubular  24  define at least two annular spaces  32  and  33  that may be used to contain at least two media  30  and  31  [partially shown for clarity]. Additionally, while not shown, should at least two intermediate tubulars  25  be used, any number of annular spaces may be created between external tubular  22  and internal tubular  24 . The additional annular spaces may be used to contain a plurality of differentiated media. 
   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&#39;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  FIG. 2 . As the pressure drop across the filter assembly  116  increases, a larger fraction of the total flow passes through the by-pass valve  134 . Those skilled in the art will appreciate that different bypass valve designs will exhibit different flow curves. In an alternative embodiment where a by-pass valve  134  is provided, the by-pass valve  134  could be opened just prior to the point at which wellbore fluid flow is reduced to the level that is predicted to damage the artificial lift system. In addition, activation of the bypass valve could alert the operator on the surface that the filter assembly  116  might require service. Such service may comprise removal of the entire artificial lift system and filter assembly, reverse operation of the artificial lift system, or back-flushing fluid through the system from the surface so as to force out matter that may have accumulated in the filter assembly. 
   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% SiO 2  and 10 to 20% Al 2 O 3 . 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 . 
     FIG. 5  is a cross-sectional view of filter assembly  116  taken perpendicular to its major axis. Screen  22 , at least one intermediate wall  25  and central conduit  24  can be seen to define at least two annular spaces  32  and  33 . In use, central passage  28  is in fluid communication with the inlet of pump  100  via inlet connector  14 . 
   Additional downhole components may be included in order to facilitate the use and recovery of the apparatus. The embodiment of the invention shown in  FIG. 4  includes filter assembly  300 , packer  302 , crossover subassembly  304 , shear sub  306 , and artificial lift system  308 . The shear subassembly  304  is intended to allow the artificial lift system  308  to be removed without removing the packer  302 , crossover subassembly  304 , and the filter assembly  300  in those instances when the packer  302  is unable to be removed from the wellbore due to sand accumulations or any other cause. The conditions where the packer  302 , crossover subassembly  304 , and filter assembly  300  may become stuck in the wellbore usually occur at the end of the filter assembly  300 &#39;s life cycle when the bypass valve  132  has opened and sand is passing through the assembly. Some of this sand may settle on top of the packer making it difficult to remove from the well. In such cases, the artificial lift system  308  may be separated from the sheer sub  306  and removed from the wellbore. The packer  302  may then be milled out of the bore and any remaining equipment fished from the well. 
   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 (H 3 PO 4 ) 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  FIG. 6 . 
     FIG. 6  depicts the multi-layer embodiment of  FIG. 3  with the addition of capillary tubes  136  and  138  that are in fluid communication with annular spaces  32  and  33 , respectively, via openings  36  in top plate  18 . When the concentration of chemical agents in the production fluid(s) falls to an ineffective level, porous media  30  and/or  31  may be recharged by providing chemical agents into annular spaces  32  and  33  via capillary tubes  136  and/or  138  from the surface. The chemical agent may be moved through the capillary tubes  136  and/or  138 , by gravity, pumping from the surface, pumping from downhole, gas pressure, pumping from a reservoir or any other method of moving a gas, liquid, fine solid, or solid in liquid suspension through a relatively long tube. Once the chemical agent is brought into contact with the medium the chemical agent is absorbed into porous medium  30  (and/or  31 ), recharging it. In an alternative embodiment shown in  FIG. 7 , the capillary tubes  236  and  238  pass through openings  36  in the top plate  18  so as to disperse the recharging chemicals along the length of the annuli  32  and  33  through perforations  240  in the capillary tubes  236  and  238 . 
   As shown in the transverse, cross-sectional view of  FIG. 12A , capillary tube(s)  35  may be formed in wall  38  of production tubing  12 . Alternatively, as illustrated in  FIG. 12B , capillary tubes may be contained within notches  37  in wall  38  of production tubing  12 . Bands or straps [not shown] at intervals along the production tubing may be used to retain capillary tube(s) within notches  37 . Chemical agent that may be in liquid, gas, or solid powder form or combinations thereof, may be introduced into filter assembly  116  by means of wall capillary tube  35 , thereby avoiding the addition of separate capillary tubes such as  136  and  138  to the apparatus, which may be more susceptible to mechanical damage within the well bore. The chemical agent employed may be the reaction product of two or more reactants. If, for example, the chemical agent were hazardous to handle, it could be produced in situ by introducing the reactants that form the agent by means of separate wall capillary tubes  35 . Similarly, binary or ternary chemical agents could be created in situ with the relative amount of each component selected depending on operating conditions. Additionally, if the chemical agent is heat activated, the line carrying the specific chemical could be routed through cooling passages in the artificial lift system [not shown] where the excess heat from the artificial lift system could heat the chemical to at least the desired temperature. Thus, the chemical could be heated while serving as a coolant for the artificial lift system. 
   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  FIG. 8 . In the particular embodiment illustrated, the dual-layer filter assembly of  FIG. 3  is modified by the addition of extension  40  comprising outer wall  41 , intermediate wall  44  and top plate  43 . Outer wall  41 , intermediate wall  44 , top plate  43 , and the inner wall may be impervious to production fluids and assembled in a fluid tight manner. Annular space  42  of extension  40  defined by outer wall  41 , inner wall  44 , top plate  43  and the inner wall is an extensions of annular space  33 . Annular space  42  may therefore function as a supply hopper for the chemical agent exposed to the production fluids in annular space  33  of filter assembly  116 . As the solid phase chemical agent is dissolved from annular space  33 , fresh chemical agent from annular space  42  will fall into annular spaces  33  under the influence of gravity. 
     FIG. 9  illustrates an alternative embodiment having separate annular hoppers for replenishing the chemical agents in annular spaces  32  and  33 . Inner tubular  14 , the artificial lift system housing  100 , and the production tubular  12  form an inner wall. Outer wall  41 , intermediate wall  44 , top plate  43 , and the inner wall may be impervious to production fluids and assembled in a fluid tight manner. Annular spaces  42  and  142  of extension  40  defined by outer wall  41 , inner wall  44 , top plate  43  and the inner wall are extensions of annular spaces  32  and  33 . Annular spaces  42  and  142  may therefore function as supply hoppers for each chemical agent exposed to the production fluids in annular spaces  32  or  33  of filter assembly  116 . As the solid phase chemical agent is dissolved from annular spaces  32  and  33 , fresh chemical agent from annular space  42  and  142  will fall into annular spaces  32  and  33  under the influence of gravity. Such an apparatus may employ chemical agents having different phases. For example hopper  142  may contain a liquid agent while hopper  42  contains a solid chemical treatment agent. 
   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  FIG. 10 . While a single-layer filter may be utilized, in the particular embodiment illustrated, filter assembly  116  is the at least dual-layer type shown in  FIG. 3 . Chemical agent reservoir  60  is adapted to be located in the annular space between the production tubing and the production casing. Reservoir  60  may be connected to supply conduit  62  via coupling  64 . Coupling  64  may be a quick-connect type of coupling that permits reservoir  60  to be wireline retrievable for refilling at the surface. Supply conduit  62  provides a fluid connection between reservoir  60  and annular space  33  of filter assembly  116  via valve or metering means  66 . The flow of liquid phase chemical agent from reservoir  60  to the filter assembly  16  may be regulated by time and/or volume by valve/metering means  66 . Valve  66  could be adjusted by sending a signal down the ESP cable or with an I-wire. Valve  66  may also comprise a metering pump which may, in certain embodiments, be electrically or hydraulically powered. The pump discharge pressure could also be utilized to adjust the valve or operate the hydraulic metering pump. When the pump is turned off the drop in discharge pressure could shut the valve and stop the flow of chemicals. Within annular space  33 , a distribution means may be provided for distributing the chemical agent in a desired pattern throughout the medium  30 . The distribution means may be a fluid conduit having a plurality of orifices sized to provide a desired delivery rate of the chemical agent to medium  30 . Reservoir  60  may be pressurized by a compressed gas in the head space above the chemical agent. Alternatively, the chemical agent may be contained within an elastomeric bladder contained within reservoir  60  and the surrounding space pressurized to provide a supply of chemical agent under pressure. In yet other embodiments, reservoir  60  may be provided with pressure equalization means to permit gravity flow of chemical agent from reservoir  60  to annular space  33 . 
     FIG. 11  depicts one alternative embodiment of the invention illustrated in  FIG. 10  wherein annular space  400  within well casing  404  above packer  402  replaces reservoir  60 . In certain embodiments, packer  402  may be a cup packer. A chemical treatment agent (which may be a liquid-phase substance) may be inserted into annular space  400  before, during or after installation of artificial lift pump  406 . 
     FIG. 13  depicts an embodiment of the invention wherein filter assembly  116  is positioned above pump  100 . This configuration permits filter assembly  116  to be wireline retrievable from the surface for maintenance and/or recharging of chemical agent without necessarily removing the artificial lift system. In the particular embodiment illustrated, pump  100  is shaft-driven from motor  84  through motor seal  82  and concentric inlet  80 . Filter assembly  16  comprises removable upper section  89  and lower section  88  that form a fluid-tight connection around motor seal  82 . In alternative embodiments, lower section  88  may encompass motor  84  or may seal to motor  84 . The arrows in  FIG. 13  depict the direction of production fluid flow from the surrounding formation, into filter assembly  116  where sand and fines are mechanically filtered out and the fluid(s) are treated with chemical agent which dissolves or desorbs from medium  30  in annular space  32 . The fluid then flows downward (under the influence of the pressure differential created by pump  100 ) through annular space  81  and into pump intake  80  where it enters pump  100  and is lifted to the surface via production tubing  12 . 
     FIG. 14  depicts another embodiment of the invention wherein filter assembly  202  is positioned above pump  100 . In the configuration depicted filter assembly  202  includes one or more intermediate tubulars  204  [only a single intermediate tubular is shown for clarity] and thus filter assembly  202  has at least two annular spaces,  206  and  208 . It will be appreciated by those skilled in the art that multiple intermediate walls may be incorporated into filter assembly  202  and thus multiple annular spaces may be defined within the apparatus. Each annular space may be used to contain a different medium to provide various functions—e.g., graduated mechanical filtration and/or treatment with different chemical agents. Intermediate wall  204  may comprise a screen, perforated tubular, or other type of porous material. Filter bottom plate  212  is non-porous so as to force fluid that enters the outermost, as fluid flows into the filter assembly from the exterior, of multiple annular spaces  208  to enter into the innermost of any number of subsequent annular spaces  206 . It is understood that any additional annular spaces between the outermost annular space  208  and innermost annular space  206  would most preferably have a non-porous bottom plate to force fluid into enter into any number of subsequent annular spaces. Filter assembly  202  is preferably designed such that wellbore fluid will pass from the exterior  216  of external tubular  218  through external tubular  218  through any medium  220  through any intermediate tubulars  204  through any additional medium  210  through artificial lift assembly intake  224  and into the central passage  28  of internal tubular  24 . This configuration permits filter assembly  202  to be wireline retrievable from the surface for maintenance and/or recharging of chemical agent without necessarily removing the artificial lift system. 
   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  FIG. 14  also allows for gas/fluid separation before the fluid enters the artificial lift assembly  230  in well conditions where the wellbore fluid has a significant amount of gas present by shrouding the artificial lift system intake and forcing the wellbore fluid to reverse direction thus causing a low pressure condition above the pump where entrained gas will be removed from the fluid. By removing the gas above the pump, the gas will rise up and away from the artificial lift system intake  224 . In the particular embodiment illustrated, pump  232  is shaft-driven from motor  236  through motor seal  234  and artificial lift system intake  224 . Filter assembly  202  comprises removable upper section  240  and lower section  242  that form a fluid-tight connection around motor seal  234 . Upper section  240  may be releasably joined to lower section  242  by connector  203 . In alternative embodiments, lower section  242  may encompass motor  236 , in which case the fluid flow may also provide cooling for the motor or may seal to motor  236 . The arrows in  FIG. 14  depict the direction of production fluid flow from the surrounding formation into filter assembly  202  where sand and fines are mechanically filtered out and the fluid(s) are treated with chemical agent which dissolves or desorbs from the at least one medium  220  in annular space  208 . The fluid then flows downward under the influence of the pressure differential created by pump  232  through annular space  246  and into artificial lift system intake  224  where it enters pump  232  and is lifted to the surface via production tubing  226 . 
   Yet another embodiment of the invention is shown in longitudinal cross section in  FIG. 15 . In this embodiment, filter assembly  16  is situated between pump  100  and pump motor  84 . Pump  100  is driven by pump motor  84  by means of shaft  90 , which may be exposed to the production fluids. The filter assembly  16  is connected to the motor seal  82 . The embodiment illustrated in  FIG. 15  may include a head unit  94  which contains at least one relief valve  96 . The relief valve  96  may be configured to open at a pre-selected differential pressure to prevent pump  100  from cavitating or otherwise being damaged if filter  16  becomes blocked. The apparatus may also be equipped with signaling means for alerting operators that the bypass valves  96  have opened and the filter assembly should be retrieved and serviced. 
     FIG. 16  is an alternative to the embodiment shown in  FIG. 15 . In this embodiment, screen  22  is in the interior of the filter apparatus and forms the wall of central conduit  102 . Outer wall  104  and screen  22  are in a spaced apart relationship so that at least one annulus  252  is created. At least one medium  250  resides in that at least one annulus  252  to allow for treatment of the wellbore fluid before the wellbore fluid enters into the artificial lift system  254 . Outer wall  104  comprises openings  26  that may be relatively large compared to the effective openings in screen  22 . In this embodiment, relatively more sand and fines may enter the filter assembly through openings  26  so that screen  22  is the final barrier to such contaminates prior to entry of the production fluid(s) into central conduit  102  and lift system  254 . 
   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.
A fluid conditioning system designed to be installed between the well perforation and the intake of a pump used to effect artificial lift is used to filter and chemically treat production fluids. The fluid conditioning system is an apparatus that provides scale inhibitors and/or other chemical treatments into the production stream. 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 a solid phase chemical. The treating chemical may be recharged or replenished by various downhole reservoirs or feeding means. In yet other embodiments, the treating chemical may be replenished from the surface by means of a capillary tube. In certain other embodiments, the apparatus may be retrievable from the surface thereby permitting recharge or replenishment of the chemical in the apparatus on an as-needed 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.