This application claims the benefit of provisional application No. 60/009,365 filed Dec. 29, 1995. 
    
    
     BACKGROUND OF THE INVENTION 
     The present invention relates to a method for enhancing the flow of heavy, viscous crude oil through an extended offshore pipeline. More particularly, the present invention relates to a method for heating the heavy crude to reduce viscosity along the length of an extended subsea pipeline. 
     Offshore hydrocarbon recovery operations are increasingly pressing into deeper water and more remote locations. Here it is very expensive to provide surface facilities and it is desirable to minimize these requirements. Often satellite wells are completed subsea and are tied to remote platforms through extended subsea pipelines as a means to reduce the production costs. Even these platforms serving as central hubs in the offshore infrastructure are provided only the minimal facilities required for collecting and partially treating the well fluids before exporting them toward onshore facilities through yet more subsea pipelines. However the subsea pipelines crucial to this infrastructure prove a weak link in certain cases where the hydrocarbon reservoir produces heavy crude oil which is subject to becoming thick and viscous at the ambient temperature of the subsea environment. Sometimes such oils are of limited trouble at the pressures and temperatures experienced at the producing well, but can cause seriously reduced throughput when cooled to lower temperatures during pipeline transport. As viscosity increases, the oil will tend to slow and greater pressures are needed to maintain flow. 
     These difficulties are combated between satellite subsea wells and platform hubs by insulating the pipelines and moving the produced well fluids as quickly as possible to minimize temperature loss. However, the long length of such pipelines renders passive insulation ineffective for pipelines whose lengths are measured in miles and tens of miles, and higher pressures may require expensive, subsea booster pumps employed at or just downstream of the wellhead. Supplying power for booster pumps, or auxiliary heating along the pipelines, is a difficult proposition for remote subsea wells and pipelines. 
     Thus, there is remains a clear need for an economical means to heat subsea pipelines in service for the transport of heavy crude oils. 
     SUMMARY OF THE INVENTION 
     Toward providing these and other advantages, the present invention is a method for enhancing the flow of heavy crude oils by heating a subsea pipeline in which a pipe-in-pipe subsea pipeline is established having a flowline for transporting well fluids in the form of an electrically conductive inner pipe concentrically surrounded by an electrically conductive protective outer pipe and the inner pipe is electrically insulated from the outer pipe along the length of the subsea pipeline. In order to maintain the temperature of crude oil at a level facilitating pipeline transportation, continuous electrical heating is provided along the length of the pipe-in-pipe subsea pipeline, this heating comprising passing alternating electrical current along the exterior surface of the inner pipe and along the interior surface of the outer pipe. In this manner the crude oil can be maintained at a temperature at which high viscosity does not prevent efficient and economical pipeline transport. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The brief description above, as well as further advantages of the present invention will be more fully appreciated by reference to the following detailed description of the preferred embodiments which should be read in conjunction with the accompanying drawings in which: 
     FIG. 1 is a side elevational view of a platform and a satellite subsea well connected by a subsea pipeline; 
     FIG. 2 is a cross sectional view of a system for direct heating of a pipeline in accordance with one embodiment of the present invention; 
     FIG. 3 is a partially cross sectioned side elevational view of the pipe insulating joint assembly of the embodiment of FIG. 2; 
     FIG. 4 is an axial cross sectional view of the centralizer of the embodiment of FIG. 2, taken at line  4 — 4  of FIG. 2; 
     FIG. 4A is a longitudinal cross sectional view of the centralizer of FIG. 2, taken at line  4 A— 4 A of FIG. 4; 
     FIG. 5 is an axial cross sectional view of a thermal insulator of the embodiment of the present invention of FIG. 2, taken at line  5 — 5  in FIG. 2; 
     FIG. 6 is a longitudinal cross sectional view of the pipeline walls and the annulus in accordance with an embodiment of the present invention; 
     FIGS. 7A-7D illustrate a progression of side elevational views of a method for installing the pipe-in-pipe direct heating system of the present invention; and 
     FIG. 8 is a partially sectioned isometric view of an alternate embodiment of a centralizer. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     FIG. 1 illustrates the environment of the present invention. Here a remote satellite well  12  is connected to platform  14  with subsea pipeline  10  which is provided with a system  10 A for direct electric heating in accordance with the present invention. Subsea pipeline  10  is brought to surface facilities  16  on platform  14  through import riser  18 . In this illustration, surface facilities  16  include initial treatment facilities  22  as well as a power source, electrical generator  24 . In similar fashion, an export riser  20  leads to a continuation of the pipeline  10  to shore facilities (not shown). It is important to note that subsea pipeline connecting satellite well  12  to its first treatment facility on the platform may be 20 to 40 or more miles long. Further, the pipeline is extremely inaccessible, resting on the seabed  26  that may be a half mile or more below the surface  28  of the ocean. 
     Components of the well fluids produced may be easily transported immediately at subsea well  12  where they retain the formation temperatures that often range from 150-180 degrees Fahrenheit. However, once produced, they have a long journey through a pipeline in a relatively cold environment. Even in relatively warm oceans such as the Gulf of Mexico, the ocean temperature at pipeline depth may be as cold as 40 degrees Fahrenheit or so. Unchecked, the heat loss across this temperature gradient over this long journey would easily cause the formation of hydrates and the precipitation of paraffins causing the pipeline flow area to become constricted or even to plug. Also, the fluid viscosities of some of the heavier crude oils are adversely impacted by low temperatures even before hydrates or paraffins become a problem. Further, upon occasion it is necessary to work over the well or to take the platform out of service for a period of time. In such instances, the pipeline is shut-in and flow ceases for a period, allowing the entire pipeline to cool to the seawater temperature. 
     These are the challenges of the present invention, to provide for direct heating along the length of the pipeline to prevent, or even reverse viscosity problems. 
     FIG. 2 is a close up view of the direct electric pipeline heating system  10 A. Pipeline  10  is shown to be a pipe-in-pipe flowline  30  having an electrically conductive carrier or outer pipe  32  and an electrically conductive product flowline or inner pipe  34  arranged longitudinally and substantially concentrically within the outer pipe. An annulus  36  is defined between the inner and outer pipes. 
     The first end or platform end of pipe-in-pipe flowline  30  is provided with a pipe insulating joint assembly  38  which structurally joins, but electrically insulates the inner and outer pipes. The first end of the pipeline is terminated at the surface facilities  16  of platform  14  (see FIG.  1 ). Returning to FIG. 2, an electrical power input  40  is connected across inner pipe  34  and outer pipe  32 . Here a first terminal  44 A is provided for power input to the outer pipe  32  and a second terminal  44 B is provided by an electrical penetrator  44 C for power input to the inner pipe  34 . The power input could be a DC source, but is here illustrated as an AC source interfacing through a transformer  42  having a primary coil  42 A connected to the generator and a secondary coil  42 B connected across the first and second terminals. 
     Thus pipe-in-pipe flowline  30  serves as a power transmission line, with the circuit completed by an electrical pathway connecting the inner and outer pipes at the second or remote end of the pipeline. In transmitting this power, the entire length of pipe-in-pipe flowline  30  serves as an electrical heater. Heat is produced by the electrical power loss from the current flow through the pipe-in-pipe flowline. For AC, this heating is due to a combination of interacting effects, including electrical resistance effects, magnetic effects (including magnetic hysteresis and eddy currents) and electromagnetic effects (including the skin effect and proximity effect). 
     In FIG. 2, the connection  46  for this pathway joining the inner and outer pipes is provided by electrically conductive bulkhead  46 A. Alternatively, the pathway could be through an electrical device  48  as illustrated schematically in FIG.  1 . This latter embodiment would provide another insulating joint assembly  38  at the second end of the pipeline with terminals  44 A and  44 B (see FIG. 2) to serve as a power takeout  46 B at the subsea wellhead end of pipeline  10 . Remote devices at the wellhead can thus be conveniently supplied with electrical power to perform such operations as boosting the well fluids pressure with a pump at the wellhead or preheating the produced fluids as they enter the pipeline. Further, power provided at the wellhead can be transported downhole, e.g., to drive a submersible pump in the wellbore or to heat the downhole tubing string. 
     It is necessary that inner pipe  34  be electrically isolated from outer pipe  32  along the entire length of pipe-in-pipe flowline  30 . Direct contact is prevented with a plurality of electrically insulative centralizers  50  spaced at frequent intervals along annulus  36 . However, it is also necessary to take steps to prevent arcing and other electrical discharges across the annulus. These steps may include careful quality control measures to prevent water and debris from entering the annulus, removing any sharp points or edges protruding into the annulus, providing an arc-resistant coating  52  on the outside of inner pipe  34 , and providing a liner  54  at the power input and insulating joint assembly  38 . 
     It is also useful to remove water from the annulus. This may be accomplished by forcing dry air or dry nitrogen through the annulus, or alternatively, by evacuating the annulus with a vacuum pump  56  to remove air and water vapor. Once evacuated, the annulus may be maintained under vacuum as part of a thermal insulation program or as part of a leak detection program as discussed later. Alternatively, it may be desired, after evacuating the annulus, to inject an arc-suppressing gas into the annulus such as Sulphur Hexafloride (SF 6 ) which is shown available in a reservoir  58  in FIG.  2 . 
     Even though direct electric heating is supplied along the length of the pipeline, appropriate steps are taken in the illustrated embodiments to limit the heat loss from the pipeline to the environment. The amount of electrical power required to maintain the inner pipe and contents at a given temperature is minimized by minimizing the heat losses in the system. Direct conductive heat transfer is limited by selecting materials for centralizers  50  that are thermally insulative as well as electrically insulative and by properly selecting the centralizer length and the spacing between centralizers. Heat loss through convection can be reduced by maintaining the annulus under a vacuum, as discussed above, or by providing insulation panels  60  between centralizers  50 . Radiant heat loss is reduced significantly by placing a low emissivity coating, such as an aluminum-coated mylar film, on inner pipe  34 , but may already be a small factor if insulative panels  60  are used. Further, it should be noted that Sulphur Hexafloride (SF 6 ) can provide thermal insulation as well arc-suppression benefits. It may also be useful to hold the vacuum in the annulus for an extended period, e.g., over several weeks, before injecting the Sulphur Hexafloride (SF 6 ) in order to remove air defused into the open cells of the low density plastic foam of insulation panels  60 . 
     FIG. 3 illustrates an insulated joint assembly  38  in greater detail. The inner pipe is isolated from the outer pipe by annular rings  62  formed from a material that is both strong and very resistant to electrical breakdown, e.g., a suitable epoxy or zirconia. Other annular spaces  63  within the insulating joint  38  are filled with similar high strength, electrically resistant materials. Liner  54  is bonded over each side of insulator interface  64  to prevent electrical breakdown due to brine in the well fluids. This figure also illustrates an electrical terminal  46  connected to the inner pipe by an electrical penetrator  46 C which passes through an electrically insulated, vacuum-tight port  46 D. In this embodiment the liner  54  terminates in a swage ring liner termination  66 . 
     FIGS. 4-4A illustrate one embodiment of insulated centralizer  50 . Here centralizers are molded and/or machined from a strong, non-charring plastic such as Nylon or a polyacetal plastic such as that marketed under the name Delrin to form collars  50 A that are secured about inner pipe  34  with non-conductive elements such as non-metallic socket head cap screws  68 . In this embodiment water and solid intrusion within the centralizer is blocked to prevent electrical discharge. A rubber liner  70  is secured about inner pipe  34  and collars  50 A are placed around the rubber liner which is captured within shoulders  80 . A key  72  on the collar fits within the gap  74  in the rubber liner. This key is opposite the open side or slit  76  of the collar and prevents any alignment of gap  74  and slit  76 . Further, it may be desirable to completely seal the slit with a silicon adhesive caulk or a silicon gasket. Such precautions may be desirable to prevent contaminants from forming a bridge from the inner pipe to the outside of centralizer  50  which is in contact with outer pipe  32 . In a another embodiment, the rubber liner  70  overlaps when wrapped around the inner pipe. This liner is taped in place and halves of a “keyless,” two-piece collar  50 A are then clamped over the rubber liner and tightened down with opposing screws  68 . 
     FIG. 8 illustrates another embodiment of the insulated centralizer  50 . Here centralizer body  50 B and tapered sleeve  78  are molded and/or machined as before from a strong, non-charring or char-resistant plastic such as Nylon or Delrin. Centralizer is assembled by placing the two halves  78 A and  78 B of the tapered sleeve around the inner pipe  34  and coating  52 . Then the tapered inner surface of the centralizer  50 B is forced longitudinally over the tapered outer surface of the sleeve  78 , providing an interference fit which secures the sleeve to the pipe  34 . Finally, centralizer body SOB is secured to the tapered sleeve  78  by adhesive bonding or by welding of the plastic parts. Precautions to prevent arcing due to contaminants are fewer and less critical with this embodiment, since the centralizer does not have any radial slits as with the other embodiments. 
     Although, the inner pipe  34  is substantially aligned coaxially with the outer pipe  32  with centralizers  50 , it is desired to provide a flow path in the form of gaps or longitudinal channels between centralizers  50  and the outer pipe  32 , through which the annulus can be evacuated or filled with an arc-suppressing gas as discussed above. This flow path may be created by making the outer diameter of the centralizers  50  a little smaller (by 0.2 to 0.4 inch, say) than the inner diameter of the outer pipe  32 , or by forming longitudinal grooves or scallops (not shown) into the outer surfaces of the centralizers  50 . 
     The centralizers are placed at longitudinal intervals which will prevent the inner pipe from buckling due to installation or operational loads. In practice, this interval between centralizers may be about 10 to 20 feet. The inner pipe is thus prevented from moving into such proximity with the outer pipe that an arc or direct contact might result. 
     FIG. 5 illustrates a cross section through pipe-in-pipe flowline  30  at a ring of insulated panels  60 . Describing the components from the inside out, the product flowline or inner pipe  34  is provided a smooth, continuous inner surface that does not promote fouling and is piggable as may be necessary to clear the line or for other purposes. The outside of inner pipe  34  is provided a thick coating  52  of an arc-resistant material such as high density polyethylene or polypropylene which may be extruded over an initial corrosion resistant coating. A pair of low density plastic foam insulation panels of a material such as polyisocyanurate are assembled about inner pipe  34  for insulative coverage between centralizers  50  (see FIG.  2 ). These may be conveniently handled in 4- to 6-foot long sections or so. These panels are glued or taped in place with electrically insulative, arc-resistant materials about the inner pipe and a seal secured with the abutting centralizers  50 . This low density foam is partially open celled, so that evacuation of the annulus, then filling it with Sulphur Hexafloride (SF 6 ) injection operations will tend to fill the voids with arc-suppressing, thermally insulative gas. Further, the surface of panels  60  may be coated for increased char-resistance. In particular, anti-char coatings such as a silicon rubber based compound marketed by Dow under the name Sylgard may be used immediately adjacent centralizers  50 . The characteristics of the low density plastic foam may be selected for inhibiting its tendency to crumble and create debris within annulus  36 . If desired, an aluminized mylar film can be affixed to the outside of the panels, shiny side out, to reduce radiant heat loss. 
     Further, the seams formed by adjoining pieces of foam insulation could allow possible contaminants such as pipe scale and/or water to form a path to the inner pipe and result in electrical failure across the annulus. The foam insulation may be conveniently wrapped with an adhesive backed membrane to ensure against this risk. A suitable membrane is permeable to air and water vapor, allowing their removal from the foam under vacuum, but blocking entry of liquid water and solids such as pipe scale. Tyvek®, a material marketed by DuPont, would be useful for such embodiments. 
     The interior of outer pipe  32  is preferably treated to prevent the formation of scale which might bridge the annulus or initiate an arc. Such treatment might include a pickling operation with acid and oil treatments, or blast cleaning followed by internal coating with epoxy or nylon or installation of a liner. If a liner is installed, it could include a mylar film to further limit radiant heat loss. 
     Finally, the outside of outer pipe  32  will typically be provided with a corrosion resistant coating and cathodic protection as commonly deployed in offshore applications, e.g., a fusion bonded epoxy coating, together with sacrificial anodes spaced at intervals along the pipeline. Further, if DC power transmission is used, the polarity should be such as to further cathodically protect the outer pipe. 
     It should be noted that AC power has several benefits over DC power, and is preferred for this application. First, the power and voltage requirements for direct electrical heating of the pipeline and power transmission to the satellite wells is within conventional AC power engineering limits and is already available on platforms in standard 60 Hertz power plant configurations. Although it may be desirable to alter the frequency in certain applications, the basic power commitments for pipe lengths up to 40 miles, and perhaps more, may be achievable without special purpose generators. Second, DC power raises significant concerns about corrosion control for the underwater pipelines, which is not an issue for AC power. Finally, in a pipe-in-pipe flowline, the skin effect and proximity effect associated with AC power cause the current to travel on the outside of inner pipe  34  and the inside of outer pipe  32 . See arrows  82  in FIG.  6 . Safety is enhanced as almost no voltage potential is present on the outside of carrier pipe  32 . 
     FIGS. 7A-7D illustrate one method for installation of a pipe-in-pipe flowline suitable for direct electric pipeline heating and other power transmission to remote subsea wells. In FIG. 7A, Carrier pipe  32 A is suspended on end in slips  90  at weld floor  92  of a J-lay installation barge. Collar/elevator  96 A engages shoulder  94  presented on the end of pipe sections of carrier pipe  32 A to secure this suspension. An end of a section of product flowline  34 A extends out of carrier pipe section  32 A. These pipes are joined together at the terminal end as shown in FIG.  2 . Since the centralizers  50  provide substantial lateral support and prevent buckling between outer pipe  32 A and inner pipe  34 A, these centralizers thereby also prevent relative longitudinal movement (sliding) between the two pipes, even when suspended vertically as shown in FIGS. 7A-7D. 
     Another concentrical arrangement of inner and outer pipe sections  34 B and  32 B, respectively, is lowered into place for joining into the pipeline while supported by the collar/elevator  96 B. The internal plug  98  on the upper end of the vertically approaching inner pipe section  34 B allows the inner pipe to extend beneath outer pipe  32 B, but not to slide farther down. 
     In FIG. 7B, inner pipes  34 A and  34 B are brought into position and welded together. Special care is taken to prevent the deposition of debris into the annulus as installation proceeds. The inner pipe weld is coated, e.g., by a shrink sleeve of polyethylene or polypropylene, which provides continuity to both corrosion coating and arc-resistant barrier coating  52  on the outside of inner pipe  34 . 
     High temperature thermal insulation material such as mineral wool  53  is placed in the annulus between the two welds as a protection to other heat sensitive materials in the annulus. Otherwise, heat might damage membranes, coatings, and/or insulative foam under the weld, creating a charred material and possible electrical path to the inner pipe. It is convenient to fabricate and install this char-resistant refractory material as “clamshell” halves similar to the foam insulation. It is only necessary that this protection extend for a few inches to each side of the weld. 
     Then outer pipe  32 B is lowered into alignment with outer pipe  32 A and welded into place. See FIG.  7 C. An appropriate corrosion coating is applied to the outer pipe weld, collar/elevator  96 A is removed, the assembled pipe-in-pipe section is lowered through the slip until pipeline is suspended by collar/elevator  96 B, and internal plug  98  is removed. See FIG.  7 D. This J-Lay process then repeats with adding successive sections to the pipe-in-pipe flowline  30 . 
     Alternatively, these vertical pipe assembly techniques may be utilized horizontally to install pipe-in-pipe flowlines by the S-Lay method. As another possible alternative, long sections, e.g., 1500 feet or so, of inner pipe  34  and outer pipe  32  may be assembled onshore, strung together into concentric relation, and sequentially reeled onto a large diameter reel for later installation offshore. 
     The pipe-in-pipe configuration of subsea pipeline  10  is also useful for leak detection. In embodiments maintaining a vacuum in the annulus, a leak in the outer pipe will manifest as water vapor in vacuum pump discharge  56 A. See FIG.  2 . Pressuring up the annulus with dry air or nitrogen will discharge bubbles  102  to locate the leak, see FIG.  1 . The exact position of the leak could then be pinpointed with an ROV inspection of the exterior of the pipeline, and an external leak repair clamp can be installed at the point of failure to seal the leak. A leak in the inner pipe will be observed as hydrocarbon vapor in the vacuum pump discharge and might be located through use of an inspection pig. Repair of an inner pipe leak will require cutting the pipeline, removal of the damaged section, and re-joining of both outer and inner pipes on the seafloor with mechanical connections. 
     Alternately, by maintaining a constant volume charge of arc-suppressing gas such as Sulphur Hexafloride (SF 6 ) in the annulus of a pipe-in-pipe flowline, any increase in annulus pressure would signal seawater intrusion through a breach in the carrier pipe. Again, the annulus could be pressured up to leave a bubble trail to reveal the location of failure. Further, in the event of any failure of the inner pipeline, the Sulphur Hexafloride (SF 6 ) could be used a as a tracer. The annulus could be pressured up incrementally and held, and the appearance of the tracer gas at the collection point would be indicative of the pressure at which the annulus pressure exceeded the flowline pressure. This then correlates roughly to position along the pipeline. Alternatively, the travel time for a charge of high pressure gas in the annulus to enter the flowline and appear at a collection point could be correlated to approximate location along the pipeline. 
     At commissioning, air and water are removed from the annulus, and arc-suppressing and thermally insulative gas is injected, if desired, as discussed above. After connecting the power input to the flowline at the platform end, the level of electrical power is brought up slowly so that any arcing initiated by minor debris or contamination might occur with minimal damage. Progress in application of power to the system and resulting temperature increases at both ends of the pipeline would be monitored carefully. When brought to operational levels, it may be desired to establish calibration of actual power and voltage input to heating output by placement of thermocouples  100  at appropriate locations along the pipeline. 
     In operation, the modified pipe-in-pipe flowline also provides convenient power transmission for direct electric heating of the pipeline and for driving remote electrical components. The heating is useful for preventing hydrate formation and paraffin deposition, and for enhancing flow of heavy crudes. This is particularly important while maintaining well fluids within a shut-in subsea pipeline. It is also useful for reversing blockages caused by hydrate formation and paraffin disposition at somewhat higher, but nonetheless practical power levels. Further, it should be noted that pulses and frequency modulation can be carried as control signals along with the power transmission to control components at remote satellite subsea wells or the like. 
     Other modifications, changes and substitutions are intended in the foregoing disclosure and in some instances some features of the invention will be employed without a corresponding use of other features. Accordingly, it is appropriate that the appended claims be construed broadly and in the manner consistent with the spirit and scope of the invention herein.
A method for enhancing the flow of heavy crude oil by heating a subsea pipeline is disclosed in which a pipe-in-pipe subsea pipeline is established having a flowline for transporting well fluids in the form of an electrically conductive inner pipe concentrically surrounded by an electrically conductive protective outer pipe and the inner pipe is electrically insulated from the outer pipe along the length of the subsea pipeline. The pipe-in-pipe subsea pipeline is electrically heated continuously along its length to maintain the temperature of crude oil at a level facilitating pipeline transportation, this heating comprising passing alternating electrical current along the exterior surface of the inner pipe and along the interior surface of the outer pipe. In this manner the crude oil can be maintained at a temperature at which viscosity does not prevent efficient and economical pipeline transport.