Patent Publication Number: US-2011067881-A1

Title: System and method for delivering material to a subsea well

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application No. 61/138,044, filed Dec. 16, 2008. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates to the delivery of materials, such as scale inhibitor chemicals, from a vessel at a surface facility to a subsea location and into a subsea well, for example, to perform a subsea scale squeeze treatment in a subsea hydrocarbon well. 
     2. Description of Related Art 
     The formation of scale, inorganic crystalline deposits, can occur throughout the equipment used in a hydrocarbon production operation. For example, in one typical situation, the formation of scale can occur as a result of waterflooding, such as when sea water is injected into a well and mixed with formation water in the well. Scale can also form upon changes in the supersaturation of solubility of minerals in the formation or produced waters that are caused by pressure and/or temperature changes. Scale formation can also be increased by nucleation sites, e.g., sand and corrosion. The scale-forming precipitates can include various minerals such as calcium carbonate, calcium sulfate, barium sulfate, magnesium carbonate, magnesium sulfate, and strontium sulfate. For example, sulfate scale deposition is likely to occur when seawater injection is used to recover deposited hydrocarbons. 
     Such scaling can occur inside and outside the well, e.g., within tubings or other equipment through which the production fluids flow from the well, and represents an important flow assurance problem in the oil and gas industry. In some cases, the scale formation can reduce or prevent flow through bores and tubings, prevent proper operation of valves and pumps, and otherwise interfere with the operation of the equipment associated with the well. 
     There are several techniques available to control scale deposition. For example, the fluid modification technique includes injecting water of different composition (e.g. aquifer water or desulfated water) to the reservoir and separating the water from the production stream. The most common technique to prevent and treat scale precipitation is the application of chemicals that function as scale inhibitors. Such chemical inhibitors, or scale inhibitors, may be aqueous based, oil based, emulsions, micro-encapsulated, porous impregnated pellets, and multifunctional products (e.g. corrosion/scale inhibitor, asphaltene/scale inhibitor, etc.). Scale inhibitors generally work by preventing nucleation and crystal growth. Many scale inhibitors can be applied into the production stream by continuous injection or into the wellbore by a scale squeeze treatment. A typical scale squeeze treatment for treating a well with a scale inhibitor includes interrupting the flow of production fluid from the well and injecting the scale inhibitor through the well into the reservoir so that the scale inhibitor interacts with the rock matrix in the reservoir to be adsorbed into the formation and then precipitated onto mineral surfaces. Typically, the squeeze treatment involves the injection of a preflush solution, followed by the injection of the chemical inhibitor (mainflush), and finally the injection of an overflush solution. Thereafter, the well is returned to operation and the scale inhibitor in the reservoir desorbs or dissolves into the fluid in the reservoir, such that the production fluid contains some scale inhibitor. The scale inhibitor generally prevents or reduces the deposition of scale from the production fluid in the tubings and other equipment through which the fluid flows. 
     Scale inhibitor can be injected into a subsea well from a surface facility such as an offshore platform or a floating production and storage and offloading (FPSO) vessel via production pipelines or flowline (which may include a riser) and associated manifolds that normally carry the production fluid upward from the subsea well to the surface facility. In this case, the flow of production through the riser is stopped. Then, the scale inhibitor is pumped into the top of the riser at the surface facility and through the riser to the subsea well and into the subsea reservoir. Low pump rates for the scale inhibitor are typically required due to a relatively high friction associated with the production flowline and/or the viscosity of the scale inhibitor, which may increase at the lower temperatures found close to the seabed. In some cases, a large volume of scale inhibitor may be used. For example, a typical 15 km-segment of production flowline may have a volume of 5,000 barrels, depending on the diameter, with the entire volume of the flowline being filled before the scale inhibitor begins to flow into the reservoir. Further, in some cases, the flowline need to be emptied and cleaned by a pigging operation before the chemical inhibitor is pumped into the wellbore in order to avoid pumping debris that exists in the flowline, such as scale, wax, and/or sand, into the formation. 
     When subsea production of different satellite wells is brought together in a manifold or flowline, scale squeeze treatment can become expensive. In this case, it may be necessary to shut down all of the wells even if only one well is to be treated since the flowline is to be used to deliver the scale inhibitor. This inconvenience can be avoided by providing a separate line from each well to a surface production facility; however, using dedicated lines may not always be possible due to engineering restrictions or capital expenditure limitations. In some cases, subsea squeeze treatments are sometimes performed using surface vessels, e.g., a Diving Support Vessel (DSV) and a flexible line attached to the subsea manifold. Subsea squeeze treatments have also been performed by placing encapsulated inhibitors into the wellhead. In that case, a Diving Support Vessel can transport the capsules, which fall down by their own weight through a flexible riser, into the sump. Diffusion of the scale inhibitor takes place due to difference in concentration gradients. 
     While such operations have been successfully used for subsea scale squeeze treatments, there exists a continued need for improved systems and methods for delivering materials, such as chemicals for a scale squeeze treatment, to a subsea well. The system and method should be capable of being used with a passage that is not defined by a riser, e.g., so that a subsea scale squeeze treatment can be performed without emptying the production fluid from the riser or reversing the flow of fluid in the riser, and should be capable of use in systems that include several wells and/or trees attached to a common production flowline. 
     SUMMARY OF THE INVENTION 
     The embodiments of the present invention generally provide systems and methods for delivering a material from a vessel at a surface facility to a subsea location and into a subsea well, such as for delivering one or more scale squeeze treatment chemicals adapted to inhibit scaling via an umbilical or other tubular member to a subsea well for a subsea scale squeeze treatment of the well. According to one embodiment, the system includes a first-stage pump located at the surface facility and configured to receive the material from the vessel. A tubular member extends from the first-stage pump to the subsea location. A second-stage pump is located at the subsea location and connected to the tubular member. For example, the second-stage pump can be disposed on the seafloor and/or as part of a tree at a head of the subsea well. The first-stage pump is configured to deliver the material through the tubular member to the second-stage pump at a first pressure, and the second-stage pump is configured to receive the material from the tubular member and inject the material into the well at a second pressure higher than the first pressure. 
     In some cases, the tubular member can be a flexible tube formed of a thermoplastic material and/or a flexible umbilical that defines a first tubular passage for receiving and delivering the material, and a second tubular passage having at least one conductive cable for communicating between the surface facility and the subsea location. The conductive cable can be configured to provide at least one of an electrical signal for controlling the operation of the second-stage pump and electrical power for powering the operation of the second-stage pump. 
     According to another embodiment, the present invention provides a method of delivering a material from a vessel at a surface facility to a subsea location and into a subsea well. The method includes operating a first-stage pump located at the surface facility to pump the material from the vessel through a tubular member extending from the first-stage pump to the subsea location, and operating a second-stage pump at the subsea location and connected to the tubular member to inject the material from the tubular member into the well. For example, the method can include providing the second-stage pump at the seafloor and/or as part of a tree at a head of the subsea well. The operation of the first-stage pump and the second-stage pump can include injecting a scale squeeze treatment chemical into the well to thereby perform a scale squeeze treatment of the well and inhibit scaling in the well and/or the riser, production pipeline, flowlines, or other equipment downstream of the well. 
     In some cases, a flexible tube formed of a thermoplastic material or a flexible umbilical can be provided as the tubular member, and the first-stage pump can be operated to pump the material through a first tubular passage of the umbilical. The umbilical can be provided with at least one conductive cable in the umbilical in communication with the surface facility and the subsea location. An electrical signal can be communicated from the surface facility to the subsea location via the conductive cable to control the operation of the second-stage pump, and/or electrical power can be provided from the surface facility to the subsea location via the electrically conductive cable to power the operation of the second-stage pump. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Having thus described the invention in general terms, reference will now be made to the accompanying drawings, which are not necessarily drawn to scale, and wherein: 
         FIG. 1  is an elevation view schematically illustrating a system for delivering material from a surface facility to a subsea location and into a subsea well according to one embodiment of the present invention; 
         FIG. 2  is a cross-sectional view schematically illustrating an umbilical according to one embodiment of the present invention; 
         FIG. 3  is an elevation view illustrating a system for delivering material from a floating production facility to a subsea location and into a subsea well according to one embodiment of the present invention; 
         FIG. 4  is an elevation view illustrating a system for delivering material from a service vessel to a subsea location and into a subsea well according to another embodiment of the present invention; and 
         FIG. 5  is an elevation view illustrating a system for delivering material from a service vessel to a subsea location and into a subsea well according to another embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention now will be described more fully hereinafter with reference to the accompanying drawings, in which some, but not all embodiments of the invention are shown. Indeed, this invention may be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. Like numbers refer to like elements throughout. 
     Referring now to the drawings and, in particular, to  FIG. 1 , there is schematically shown a system  10  for delivering a material, such as chemicals for performing a scale squeeze treatment to a subsea well  12 . The system  10  generally includes a plurality of pumping units  14 ,  16  in a multi-stage pumping arrangement for delivering the material from one or more vessels  18  located at a surface facility  20  to a subsea location  22  via a tubular member  24  and injecting the material into the well  12 . 
     The surface facility  20  can be any type of surface unit, such as an offshore platform or oil rig of any type. The vessel  18  can include one or more storage tanks mounted on the surface facility  20  or containers that are brought by ship or otherwise to the facility  20  and fluidly connected to the facility  20  so that the material in the vessel  18  can be received by a first-stage pumping unit  14  located at the surface facility  20 . 
     The first-stage pumping unit  14  receives the material and pumps the material through the tubular member  24 , such as an umbilical, that extends from the surface facility  20  to a subsea location  22 . In particular, as shown in  FIG. 1 , the tubular member  24  can extend to a second-stage pumping unit  16  located at the subsea location  22 , e.g., at or proximate to the seafloor  26 . The tubular member  24  defines one or more passages for the flow of the material. The first-stage pumping unit  14  delivers the material through the tubular member  24  and to the second-stage pumping unit  16  at a first pressure, typically higher than atmospheric pressure but insufficient for delivering the material into the well  12  and reservoir. It is appreciated that the pressure of the material may decrease from the inlet  28  of the tubular member  24  at the first-stage pumping unit  14  to the outlet  30  of the tubular member  24  at the second-stage pumping unit  16 . For example, the material can be stored in the vessel  18  at approximately atmospheric pressure, the first-stage pumping unit  14  can raise the pressure to a higher pressure to deliver the material through the tubular member  24 , and the material can be provided to the second-stage pumping unit  16  at an even higher pressure. 
     The first-stage pumping unit  14  can be powered by a power source  32 , e.g., an electric or hydraulic power source. The operation of the power source  32  and the first-stage pumping unit  14  can be controlled by a controller  40 , e.g., a computer device configured to receive manual inputs from a human operator and/or operate according to a program of predetermined and defined commands and parameters. The controller  40  and the power source  32  can also be used to control and/or power the other components of the system  10 , including the second-stage pumping unit  16 . In some cases, the controller  40  can be a high pressure intervention control system unit. 
     The second-stage pumping unit  16  at the subsea location  22  is connected to the tubular member  24  and receives the material from the first-stage pumping unit  14  via the tubular member  24 . The second-stage pumping unit  16  raises the pressure of the material and injects the material into the well  12  at a second pressure that is higher than the first pressure achieved by the first-stage pumping unit  14 . 
     The multi-stage pumping system  10  of the present invention can provide the material to the well  12  with sufficient pressure for injection, while providing a relatively limited pressure of the material throughout the rest of the system  10 . For example, if the first-stage pumping unit  14  were operated without the second-stage pumping unit  16 , a greater pressure would be required in the tubular member  24  to provide sufficient pressure at the subsea location  22  for injection of the material into the well  12 . Typically, the first-stage pumping unit  14  would be required to provide the material with a pressure that is at least as great as the sum of the pressure drop that occurs in the tubular member  24  between the inlet  28  and outlet  30  and the pressure required for injection into the subsea well  12 . In some cases, e.g., where the tubular member  24  is an umbilical or a low-pressure hose or tube with a relatively narrow diameter, and/or the tubular member  24  is a long member for deepwater applications or otherwise, the pressure drop along the length of the tubular member  24  can be relatively great. In such cases, the required pressure at the inlet  28  of the tubular member  24  for overcoming both the pressure drop through the tubular member  24  and the pressure required at the subsea location  22  for injection into the well  12  can exceed the strength of the tubular member  24 . Thus, for a single-stage pump system, it may be required to provide a tubular member  24  with a high strength to withstand the high pressures required and/or to provide a tubular member  24  with a relatively large diameter so that the pressure drop therethrough is not excessively high. 
     On the other hand, the second-stage pumping unit  16 , which is provided at the subsea location  22  and downstream of the tubular member  24 , can be used to raise the pressure to a level sufficient for injection into the well  12  so that the pressure in the tubular member  24  can be limited to a level that is within the operating limits of the tubular member  24 . In this way, the pressure of the material provided by the first-stage pumping unit  14  to the tubular member  24  can be sufficient to overcome the pressure drop through the tubular member  24  but less than the sum of the pressure drop through the tubular member  24  and the pressure required at the subsea location  22  for injection into the well  12 . Thus, it may be sufficient to use a tubular member  24  with a relatively lower strength and/or a relatively small diameter. Even in deepwater applications where the tubular member  24  is long, an umbilical can have the sufficient strength and size to accommodate the flow of the material and the pressure required for maintaining the flow of the material therethrough. For example, the tubular member  24  can be structured to have a strength that is greater than the pressure drop that occurs in the tubular member  24  so that the tubular member  24  can withstand the pressure required to deliver the material therethrough; however, the tubular member  24  can be structured to have a strength that is less than the sum of the pressure drop that occurs in the tubular member and the pressure required for injection into the subsea well  12 . In particular, in some cases, the tubular member  24  can be structured to provide a burst strength of 15,000 psi or less, and the material can be provided at a maximum pressure in the tubular member  24  that is between 3,000 psi and 5,000 psi. 
     For example, the tubular member  24  of  FIG. 1  is a flexible umbilical, and the cross-section of the umbilical is further illustrated in  FIG. 2 . The umbilical is a composite cable that includes an outer sheath  42  that contains a plurality of longitudinal members or functional components, such as tubes or hoses formed of thermoplastics or steel or other metals, electrically or optically conductive cables, strength members, and the like. For example, as shown in  FIG. 2 , the umbilical includes hollow, cylindrical tubes  44   a ,  44   b ,  44   c  that define tubular passages  46  for the delivery of chemicals or other materials between the surface facility  20  and the subsea location  22 . For example, one or more of the tubular passages  44   a ,  44   b ,  44   c  can be used for the delivery of the scale inhibitors during a subsea scale squeeze operation or for the delivery of hydraulic fluids or the like for other operations. The umbilical also includes conductive communication cables  48  that can be formed of electrical or optical conductors, such as solid or twisted copper or aluminum cables or fiber optic cables. The communication cables can be used for communication of control signals, for transmission of electrical power, and/or for the communication of information, such as information collected by sensors or other devices at the subsea location  22 . The cables can be contained in sheaths  50  of plastic or other protective materials. Strength members  52  can be formed of steel, composite materials, or the like and used to increase the strength and/or stiffness of the umbilical. In addition, other members or materials can be provided within the outer sheath  42 . For example, in some cases, the space  54  between the various members in the sheath  42  can be filled with plastic or other materials to increase the strength, buoyancy, rigidity, or seal of the umbilical. 
     It is appreciated that the umbilical shown in  FIG. 2  is an exemplary tubular member  24  that can be used in the system  10  of the present invention, and other tubular members can also be used, including umbilicals of various sizes, configurations, and materials. For example, in some cases, the tubular member  24  can be a flexible tube formed of a polymer, a thermoplastic material, a reinforced composite material, or the like. The tubular member can be a dedicated device (or a dedicated fluid passage in a composite umbilical or other device) that is used for delivery of the material to the well but that is not used for delivery of production fluids from the well, and the tubular member (or the dedicated passage) can be sized accordingly, e.g., smaller than a typical riser that delivers production fluids from a subsea well to a floating production facility. For example, in some cases, the internal diameter of the fluid passage of the tubular member that is used for delivering the material to the well can be between about ¼ inch and 4 inches, such as about such as about ½ inch, 1 inch, or 2 inches, 3 inches, or 4 inches. For example, the first tubular passage  44   a  of the umbilical shown in  FIG. 2  can have a diameter of about ¼ inch or ½ inch and can be used for delivering the material to the well  12 . For situations where a greater volume of material is to be delivered to the well  12 , the tubular member  24  can be a larger hose, such as a 3- or 4-inch diameter hose formed of a composite material, such as a thermoplastic matrix material with a synthetic aramid or other reinforcement material. 
     The multi-stage pump system  10  of the present invention is illustrated with two pumping units  14 ,  16  in  FIG. 1 , and each pumping unit  14 ,  16  typically includes one pump, but additional pumps or pumping units  14 ,  16  can be provided in other embodiments. For example, additional pumps can be located at the surface facility  20 , subsea location  22 , or therebetween. Additional pumps can be configured in parallel with the illustrated pumping units  14 ,  16  to provide increased pumping capacity or redundancy, and/or additional pumps can be provided in series with the illustrated pumping units  14 ,  16  to successively raise the pressure of the material along the flow path of the material. Some or all of the pumping units  14 ,  16  can include filters to prevent the delivery of solids and particles and thereby prevent the injection of such solids and particles into the well  12  and the reservoir formation. Further, each pumping unit  14 ,  16  can be adapted to selectively pump chemicals and/or to mix chemicals if necessary. 
     Sensors  60  can be provided for monitoring relevant operational parameters, such as pressure, temperature, flow, viscosity, or the like. Such sensors  60  can be provided in the vessel  18 , pumping units  14 ,  16 , tubular member  24 , or elsewhere throughout the system  10 . Signals from the sensors  60  can be communicated to a central control device, such as the controller  40 , which can then adjust the system parameters according to the conditions sensed by the sensors  60 , e.g., by adjusting valves throughout the system  10 , by controlling the operational state and speed of the pumping units  14 ,  16 , and by controlling the operation of heaters or other equipment throughout the system  10 . The controller  40  can also receive other signals from sensors installed inside the tree or within the wellbore. Sensors at the subsea location  22  are typically configured to communicate with a surface location, e.g., by sending signals to the controller  40  via the umbilical. If the controller  40  is not located at the same surface facility  20  where the umbilical is connected, then an additional communication link, such as a wired or wireless connection, can be provided between the surface facility  20  and the controller  40 . 
       FIG. 3  illustrates a system  10  according to another embodiment of the present invention in which the second-stage pumping unit  16  is provided as an integral part of a subsea tree  62 . As illustrated, the surface facility  20  is a floating production facility, such as an offshore platform at the ocean surface  34 . The first-stage pumping unit  14  is located in the floating production facility  20 . The tubular member  24  is an umbilical and connects the first-stage pumping unit  14  to the second-stage pumping unit  16 , which is located on the seafloor  26  as part of a subsea tree  62 , which generally controls the flow of fluids into and out of the well  12 . The second-stage pumping unit  16  can be located proximate to, but separate from, the tree  62 . Alternatively, as shown in  FIG. 3 , the second-stage pumping unit  16  can be an integral part of the tree  62 , i.e., part of a single piece of equipment that is deployed as one unit. In either case, the umbilical can be connected to the second-stage pumping unit  16  via a subsea umbilical termination assembly  68 . Further, as illustrated, the umbilical can be fluidly connected to additional segments that extend to other wells or the like. 
     In another embodiment, shown in  FIG. 4 , the surface facility  20  is a service vessel such as an FPSO. The service vessel can include the first-stage pumping unit  14 , the vessel  18  for providing the scale inhibitor or other materials for injection, the controller  40 , and the power source  32 , so that the service vessel can provide the material for the injection operation. In addition, the service vessel can be used to deploy the umbilical or other tubular member  24 . In this regard, a winch apparatus  64  can be used to control the unreeling of a cable  66  attached to the umbilical termination assembly  68  that is connected to the umbilical. As the cable  66  is unreeled from the service vessel, the umbilical termination assembly  68  can be lowered to the subsea location  22 , thereby deploying the umbilical, which can also be unreeled from the service vessel, e.g., from reel  70 . A remote-operated vehicle (ROV) or other submersible control device can be used to assist in connecting the umbilical termination assembly  68  to the second-stage pumping unit  16  that is attached to, or part of, the subsea tree  62 . Alternatively, the umbilical termination assembly  68  can be adapted to attach itself to the second-stage pumping unit  16  and/or the tree  62 , e.g., autonomously or under operator control. In some embodiments, the umbilical termination assembly  68  can include additional equipment to assist in attaching the umbilical termination assembly  68  to the second-stage pumping unit  16  and/or the tree  62 , such as a global position system (GPS) device, one or more cameras, thrusters for controlling the location and orientation of the umbilical termination assembly  68 , electric and/or hydraulic systems, and the like. As shown in  FIG. 4 , buoyancy devices  72  can be attached at a plurality of positions along the length of the tubular member  24  so that the buoyancy devices  72  are deployed to different depths when the tubular member  24  is generally vertically oriented. The buoyancy devices  72  generally reduce the forces exerted throughout the tubular member  24  and on the connections of the tubular member  24  due to the weight of the tubular member  24 . 
     In another embodiment, shown in  FIG. 5 , the second-stage pumping unit  16  is connected to the tubular member  24  and is deployed from the surface facility  20  with the tubular member  24 . For example, as illustrated, the tubular member  24  can be an umbilical, and the umbilical and the cable  66  can be connected to the second-stage pumping unit  16  before being deployed. The second-stage pumping unit  16  can be deployed with the umbilical by using the winch apparatus  64  to control the unreeling of the cable  66 . As the cable  66  is unreeled from the service vessel, the second-stage pumping unit  16  can be lowered to the subsea location  22 , thereby deploying the umbilical, which is also unreeled from the service vessel. The location and configuration of the second-stage pumping unit  16  can be controlled using a remote-operated vehicle (ROV) or other submersible control device or by using additional equipment provided with the second-stage pumping unit  16 , such as a global position system (GPS) device, one or more cameras, thrusters for controlling the location and orientation of the umbilical termination assembly  68 , electric and/or hydraulic systems, and the like. 
     With the tubular member  24  configured to connect the first- and second-stage pumping units  14 ,  16 , the system  10  can be used to selectively inject materials into the subsea well  12 . In a typical injection operation, the first-stage pumping unit  14  operates at a relatively lower pressure, and the second-stage pumping unit  16  operates at a relatively higher pressure. The pumping units  14 ,  16  can provide a variable rate of flow of the materials into the well  12 , and the system  10  can selectively pump a series of materials into the well  12 . For example, different chemicals for performing a preflush, mainflush, and overflush operation can be stored in the vessel(s)  18 . The different chemicals can be delivered by the system  10  to the well  12  successively or simultaneously. In some cases, the vessel(s)  18  can include heating devices, such as resistance heaters or heat exchangers, to adjust the temperature of the chemicals, e.g., to heat the chemicals and thereby increase the flow rate of the chemicals through the tubular member  24 . 
     The tubular member  24  can be configured to communicate between the pumping units  14 ,  16 , e.g., in cases where the tubular member  24  is an umbilical. Thus, the umbilical can transport chemicals for a scale squeeze treatment operation as well as communicating signals from sensors at each end of the umbilical, communicating control signals, e.g., for controlling the operation of the pumping units  14 ,  16 , and/or communicating power, e.g., for operating the pumping units  14 ,  16 . More particularly, signals from sensors  60  at the subsea location  22  can be communicated via the umbilical to the controller  40  at the surface facility  20 , and the controller  40  can provide via the umbilical either or both of operating power for operating the second-stage pumping unit  16  and operating commands for controlling the operation of the second-stage pumping unit  16  and thereby controlling the injection of materials for the subsea scale squeeze treatment. Communication of such signals through the tubular member  24  can be performed using electrical signals through electrically conductive elements (e.g., copper wires) of the tubular member  24  or using optical signals through optically conductive elements (e.g., fiber optics) of the tubular member  24 . In some cases, the second-stage pumping unit  16  can be powered by the subsea tree  62  or via a flying lead that is connected to the subsea umbilical termination assembly  68 . 
     In some cases, the amount of material, such as chemical scale inhibitor, that is used is relatively less than that which would otherwise be required in a conventional method of delivering the material to the subsea well  12  via a production pipeline or flowline, e.g., because the diameter and the volume of the tubular member  24  can generally be less than a production pipeline by virtue of the multiple-stage pumping arrangement of the present invention. Further, if the tubular member  24  is an umbilical or other relatively low-pressure, low-diameter member that is not used for delivering production fluids from the well  12 , the amount of debris and solids that are pumped into the wellbore during injection into the well  12  can be reduced. That is, while a pipeline or flowline typically contains such debris and solids, which may be injected into the well  12  if the pipeline or flowline is used for injecting fluids into the well  12 , such injection of debris and solids can generally be avoided by using a separate tubular member  24  for injecting the scale inhibitor or other materials into the well  12 . It is also appreciated that, by using a separate tubular member  24  for injection of the material, downtime associated with the injection of materials through the production pipeline or flowline can generally be avoided or reduced. 
     Many modifications and other embodiments of the invention set forth herein will come to mind to one skilled in the art to which this invention pertains having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is to be understood that the invention is not to be limited to the specific embodiments disclosed and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.