Abstract:
The present invention discloses a method and system for insulating wells wherever heat transfer is a problem, the method comprising using dual concentric vacuum insulated tubing layers, preferably with the joints staggered with respect to one another. The method can be combined with other insulating methods, and well as with other subsidence mitigation techniques.

Description:
PRIOR RELATED APPLICATIONS 
       [0001]    This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/911,378 filed Dec. 3, 2013, entitled “Dual Vacuum Insulated Tubing Well Design,” which is incorporated herein in its entirety. 
     
    
     FIELD OF THE INVENTION 
       [0002]    The invention relates to well configurations for use in areas of permafrost, such as Alaska and Siberia, and other areas where temperature control is a concern. 
       BACKGROUND 
       [0003]    According to the US Geological Survey estimates, the Arctic region, mostly offshore, holds as much as 25% of the world&#39;s untapped reserve of hydrocarbons. Therefore, petroleum producers have shown significant interests in exploring oil and gas reserves in Arctic regions, particularly with the depletion of conventional hydrocarbon reservoirs. The areas of interest for oil and gas production mainly include Barents Sea, the Russian arctic, onshore Russia, Chukchi Sea, Beaufort Sea, the Canadian arctic islands, northern Canada, and the east coast of Greenland. 
         [0004]    Arctic areas are typically overlain by substantial permafrost layers on the order of 150 to 500 meters thick, which can be continuous from the surfaces, or discontinuous with intermittent unfrozen zones. To mobilize cold hydrocarbon deposits, heat is added to the reservoir until the hydrocarbons are fluid enough to be pumped to the surface. Commonly used in situ extraction thermal recovery techniques include a number of steam-based heating methods, such as steam flooding or steam drive (SD), cyclic steam stimulation (CSS) or “huff-and-puff”, and Steam Assisted Gravity Drainage (SAGD), as well as various derivatives of these techniques. 
         [0005]    SAGD is the most extensively used enhanced oil recovery technique for in situ recovery of bitumen resources in the McMurray Formation in the northern Alberta oil sands and other reservoirs containing viscous hydrocarbons. In a typical SAGD pattern, two horizontal wells are vertically spaced by 4 to 10 meters (m). The production well is located near the bottom of the pay and the steam injection well is located directly above and parallel to the production well. In SAGD, steam is injected continuously into the injection well, where it rises in the reservoir and forms a steam chamber. The heat from the steam reduces the oil&#39;s viscosity, thus enabling it to flow down to the production well and transported to the surface via pumps or lift gas. 
         [0006]    As its name implies, generation of high quality, high temperature and high pressure steam is a prerequisite for the SAGD process. Specifications for the steam used for SAGD are 100% quality, 7,000-11,000 kPa pressure and 238° C.-296° C. temperature. Steam capacity (flowrate) is determined by the steam-to-oil (SOR) ratio which normally ranges around 2˜4. Considering oil production volume (10,000˜100,000 BPD depending on the well size), water requirement for steam generation is immense and the cost to create high quality steam is also highly significant. 
         [0007]    As the steam is being transported to the payzone, heat is lost, causing the permafrost around the well to melt and resulting in settling of the soils due to the thaw. Thaw settlement becomes significant when steam carrying wells increase the temperature of surrounding soil and create a permafrost thaw bulb (see e.g.,  FIG. 1 ), thus reducing load carrying capacity of the soil and damaging surface structures. Permafrost thawing may have even more significant effects if areas of low thaw settlement (sands and gravels) are adjacent to areas sensitive to settlement (silts and clays), creating differential settlement. This differential settlement overstresses the well tubing and induces pipe bending strain and can result in loss of a well. As most thermal development takes place on pads, over time the thaw bulbs propagated from a single well can coalesce and form a thaw slot. Thaw slots introduce additional stresses, which can accelerate damage to the wells. 
         [0008]    Methods to limit heat loss from wellbores have included the use of gelled diesel or insulated packer fluids in an annulus and/or using cement with higher thermal insulation properties. However, these methods have been less than satisfactory. 
         [0009]    Another method of limiting heat loss uses vacuum insulated tubing (VIT), a typical sample of a VIT with partial cutaway is shown in  FIG. 2 . Vacuum insulated tubing has been widely used to limit heat loss from a wellbore, but its effectiveness has been limited, primarily due to the couplings. Couplings are a hot spot in that they do not have the same insulation properties as the main body of the joint. Accelerated heat loss can also happen when single or multiple joints of VIT lose their vacuum properties and lose heat close to the rate of a regular joint of tubing. 
         [0010]    Thus, what are needed in the art are better methods of insulating wellbores in the Artic regions and other areas where temperature control is a concern. 
       SUMMARY OF THE DISCLOSURE 
       [0011]    This disclosure provides a well configuration to limit heat transfer and the damage that can result thereby. Generally speaking, the concept requires using not only VIT but also a concentric ring of VIT intermediate casing (VIC) through the permafrost zone. In other words, the well is completed with dual concentric vacuum insulated tubulars. Without some method of reducing heat loss, it is unlikely that thermal developments in Arctic regions will be initiated due to the risk of melting permafrost and subsequent subsidence. The ability to limit heat loss to the permafrost is thus an enabling technology, advancing thermal recovery methods in the Arctic. Further, although specifically designed for Artic use, the inventive well completion configuration can be used anywhere where heat transfer is an issue. 
         [0012]    A dual vacuum insulated string reduces heat loss to a greater degree than does a single vacuum insulated string. Other advantages include mitigating accelerated heat loss in the event that a single joint fails or loses its vacuum properties and the higher heat loss experienced through the coupling or connectors on each joint. Since the couplings typically do not have vacuum insulated properties these act as hot spots at every connection. However, in a dual vacuum insulated string, the couplings can be staggered to thus limit heat loss through the inner couplings, since these joints will be encased inside a second insulated string. 
         [0013]    Advantages of the dual vacuum tubular well design are based on the fact that while it is a passive system, it offers substantially greater insulation than does regular tubing with insulating annular fluid or a single string of VIT. Installation of the additional string of vacuum insulated casing is no different than similarly sized casing and can be handled by existing rig equipment. Current VIC strings are not made in a wide enough bore to provide the second outer string, and thus, VIT in a wider bore may need to be manufactured. 
         [0014]    The use of vacuum insulated tubulars is also gaining popularity in deepwater developments for flow conformance. The use of the dual vacuum concept in deepwater wells could also decrease conformance issues. The dual vacuum concept can also be applied in hot environments where heat transfer in the opposite direction is an issue. 
         [0015]    Cold drilling fluid can aggravate lost circulation. This cold drilling fluid can be a problem in deep-water wells where the long risers significantly cool the drilling fluid. VIT with offset connections may alleviate this problem. 
         [0016]    The inventive well configuration can be used in any well completion wherein heat transfer presents an issue that needs to be addressed. Thus, it can be used in any steam based enhanced oil recovery technology, including SD, CSS, SAGD, ES-SAGD, VAPEX and the like. Further, although contemplated as particularly useful in steam injector wells, the methods can also be applied to production wells and oil pipelines, whenever there is a need to mitigate against heat loss. One particular use is in deepwater developments to prevent wax and hydrate buildup in production wells and delivery pipelines. 
         [0017]    In addition, the dual vacuum insulated pipe configuration can be used with any well completion configuration. Referred to as a casing program, the different levels include production casing, intermediate casing, surface casing and conductor casing, including the use of cement, gravel pack, perforated casing or slotted liners, flow control devices, and the like. The configuration could also be used with open hole completions, but such are unlikely to be useful in the unconsolidated oil sands common in Canadian fields. 
         [0018]    The invention includes one or more of the following embodiments, in any combination thereof: 
         [0019]    A method of well completion in cold reservoirs; said method comprising completing at least a portion of injector wells and producer wells with concentric dual vacuum insulated piping. 
         [0020]    An improved method of well completion, the method comprising insulating a well with a layer of vacuum insulating piping, the improvement comprising insulating said well with two concentric layers of vacuum insulating tubing (VIT), wherein joints from a first layer of VIT are staggered from joints of a second layer of VIT, and wherein a layer of insulating fluid is provided between said two layers of VIT. 
         [0021]    A hydrocarbon well configuration, the hydrocarbon well configuration comprising an inner layer of VIT casing surrounded by an outer layer of VIT intermediate casing, and wherein couplings from said inner layer are staggered from couplings from said outer layer. 
         [0022]    A method as herein described wherein couplings from said dual vacuum insulated piping are staggered. 
         [0023]    The method wherein said producer wells have concentric dual vacuum insulated piping in at least a permafrost zone. 
         [0024]    The method wherein said injector wells have concentric dual vacuum insulated piping at least until a payzone is reached. 
         [0025]    The method wherein said joints of an inner layer of vacuum insulated piping are staggered from joints of an outer layer of vacuum insulated piping. 
         [0026]    The method wherein a layer of insulative fluid is pumped in between said concentric dual vacuum insulated piping. 
         [0027]    The method wherein said insulative fluid comprises a gas selected from diesel, methane, CO2, N2O, flue gas and air, or combinations thereof. 
         [0028]    The well configuration comprising a layer of insulating fluid between said inner layer and said outer layer. 
         [0029]    The well configuration comprising a third surface casing. 
         [0030]    The well configuration comprising a layer of insulating cement or other insulative fluid outside of said surface casing. 
         [0031]    The well configuration wherein said insulative fluid comprises methane or CO2 or insulative packing fluid. 
         [0032]    The well configuration wherein the cyclic thermal stresses experienced by the outer layer of VIT intermediate casing in contact with the cement outside of said intermediate casing are vastly reduced due to the insulative properties of the inner layer of VIT. 
         [0033]    As used herein, the term “steam quality” is defined as the ratio of the mass of water vapor to the total mass of water vapor and liquid of a steam sample. Thus, a steam quality of 0% would be pure liquid, while a quality of 100% would be pure vapor. 
         [0034]    By “VIT” or vacuum insulated tubing or similar phrase what is meant is a two layer pipe, with an insulating vacuum between the two layers. The term also includes, however, backfilled VITs having an inert gas in the space between the two layers. 
         [0035]    By “VIC” or “VIT intermediate casing” or similar phase, what is meant is a second string of VIT tubing over the inner string. Thus, there are a pair of concentric two layer pipes, each having a vacuum or inert gas filled space. 
         [0036]    The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise. 
         [0037]    The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated. 
         [0038]    The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive. 
         [0039]    The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim. 
         [0040]    The phrase “consisting of” is closed, and excludes all additional elements. 
         [0041]    The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention. 
         [0042]    The following abbreviations are used herein: 
         [0000]    
       
         
               
               
               
             
           
               
                   
                   
               
               
                   
                 ABBREVIATION 
                 TERM 
               
               
                   
                   
               
             
             
               
                   
                 ATM 
                 Atmosphere 
               
               
                   
                 CAPEX 
                 Capitol expenses 
               
               
                   
                 CPF 
                 Central processing facility 
               
               
                   
                 CSS 
                 Cyclic steam stimulation 
               
               
                   
                 ES-SAGD 
                 Expanding solvent SAGD 
               
               
                   
                 OPEX 
                 Operating expenses 
               
               
                   
                 OTSG 
                 Once-through steam generator 
               
               
                   
                 SAGD 
                 Steam-assisted gravity drainage 
               
               
                   
                 SD 
                 Steam drive 
               
               
                   
                 TDS 
                 Total dissolved solids 
               
               
                   
                 VAPEX 
                 Vapor extraction 
               
               
                   
                 VIT 
                 Vacuum insulated tubing 
               
               
                   
                 VIC 
                 VIT intermediate casing 
               
               
                   
                   
               
             
          
         
       
     
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0043]      FIG. 1A  shows the fully thawed (solid line) and partially thawed (dotted outline) bulbs surrounding typical injection and producer wells at 3 years.  FIG. 1B  shows the fully thawed (solid line) and partially thawed (dotted outline) bulbs surrounding typical injection and producer wells at 18 years. Thaw bulbs can cause the ground to subside and loss of equipment or even an entire well.  FIG. 1C  shows the fully thawed (solid line) and partially thawed (dotted outline) bulbs surrounding VIT and dual VIT VIC thaw bulbs at 18 years. 
           [0044]      FIG. 2  shows a typical vacuum insulated tubing or VIT. 
           [0045]      FIG. 3  illustrates one exemplary well completion scenario. 
           [0046]      FIG. 4A  shows a cut-away length of exemplary dual VIT and VIC configurations.  FIG. 4B  shows a cross-section of a single VIC configuration.  FIG. 4C  shows a cross-section of an exemplary dual VIT and VIC configurations. 
           [0047]      FIG. 5A  shows depth vs. thaw radius with VIT. For comparison,  FIG. 5B  shows measured depth vs. thaw radius with dual VIT+VIC wells. As can be seen, the dual VIT and VIC configuration slows the growth of thaw bulb radii significantly. 
           [0048]      FIG. 6A  shows a nested well with aligned coupling.  FIG. 6B  shows a nested well with staggered or offset couplings.  FIG. 6C  inset of  FIG. 6A  is shown in greater detail a nested well with aligned coupling.  FIG. 6D  inset of  FIG. 6B  is shown in greater detail a nested well with staggered or offset couplings. 
           [0049]      FIG. 7  shows a traditional VIT configuration. 
           [0050]      FIG. 8  shows the heat loss modeling results of the wells of  FIG. 6A ,  FIG. 6B  and  FIG. 7  assuming three five fold varying levels of thermal conductivity (k), which is the property of a material to conduct heat. In Imperial units, thermal conductivity is measured in BTU/(hr·ft·° F.). 
       
    
    
     DETAILED DESCRIPTION 
       [0051]    The disclosure provides a novel method, apparatus and system for reducing heat losses in oil wells, and can be advantageously applied to any oil recovery, but is especially beneficial in Artic or deepwater and other very cold reservoirs where heat loss should be minimized. 
         [0052]    Generally speaking, the disclosure provides a dual insulative tubing system, wherein at least two concentric vacuum insulative pipes are used, providing two concentric vacuum (or inert gas filled) layers to insulate against heat loss. If the joints for each layer are staggered, heat loss at the joints can also be minimized. 
         [0053]    An additional layer of insulation can be had if an insulative gas, such as methane, is pumped down in between the two layers. Other thermally insulative gas options include CO2, N2O, flue gas and air. 
         [0054]    Traditional insulative layers can also be combined with the dual VIT-VIC well design, including the use of insulative gels and liquids, methane, diesel, thermal cement, insulating packer fluids such as N-SOLATE™ from Halliburton or ISOTHERM™ or SAFETHERM from Schlumberger, Glass microsphere such as 3M&#39;s Glass Bubbles and Water-Superabsorbent Polymers from Baker Hughes, and the like. In addition to enhanced well insulation, other mitigation options to reduce thaw subsidence driven well deformations can be combined with the methods and well designs herein, including increased well spacing, reduced well operating temperatures, and various combinations of the above options. 
         [0055]    The dual vacuum insulative tubing can be used wherever heat loss is a problem, and in particular can be used in the permafrost zone of both injector and producer wells. Further, injector wells can be have dual vacuum insulative tubing along their entire pre-payzone length, thus delivering maximal steam quality to the payzone. 
         [0056]    The VIT can be of any design known in the art or to be developed. Exemplary VITs are described in U.S. Pat. No. 3,720,267, U.S. Pat. No. 3,397,745, U.S. Pat. No. 4,512,721, U.S. Pat. No. 7,677,272, U.S. Pat. No. 7,854,236. VIT is also commercially available, e.g., from Industrial Technology Management (CA), who sells a variety of tubing sizes up to 4.5 inches and with varying degrees of thermal protection, including inert gas back-filled VIT. Shengli Petroleum has VIT up to 5 inches. Isothermica and DoubleOil Petroleum Services Co. are additional suppliers. Discussions are in progress with manufacturers to have VIT prepared in a bore large enough for VIC use in field testing in the Surmont and/or Ugnu reservoirs. 
         [0057]    A vacuum is an ideal insulator. Creating a vacuum between the two pipes minimizes both gas convection and conduction heat transfer between the inner and outer pipes. Radiative heat transfer is minimized by providing a reflective blanket of insulation over the outside diameter of the inner tube. The inner and outer pipes are welded together, after which the vacuum is created, and the tubing sealed. 
         [0058]    Once a vacuum has been established within the annulus between the two pipes, it must be maintained. There is a tendency for molecules to be desorbed from the metal matrix, but also during subsequent oil production, corrosion of the vacuum insulated tubing (VIT) string will generate hydrogen. Some of this hydrogen will permeate into the vacuum annulus, reducing it insulating ability. 
         [0059]    The problem of vacuum loss can be solved with “getter.” Essentially, getter captures hydrogen, and traps it via chemical bonding. There are two types of getter used. A non-evaporable getters works by surface adsorption followed by bulk diffusion into the getter matrix. An organic getter absorbs hydrogen through a dehydrogenation reaction. The getter is typically purchased as granules or tablets, and is added during the fabrication process. The multilayer and gettered high vacuum insulated tubing systems (VIT) substantially improve thermal performance having conductivity values in the range of 0.0018-0.0023 Btu/Hr-Ft-° F. (0.003-0.004 w/mK). 
         [0060]    Another possible solution is to backfill the vacuum. The first insulated tubing consisted of an Argon gas backfilled insulating system having thermal conductivity values in the range of 0.015 Btu/Hr-Ft-° F. (0.026 w/mK). 
         [0061]    An illustration of an exemplary completion is found in  FIG. 3 . In  FIG. 3  an injection well is completed of using dual VIT  32  and VIC  33  configuration, wherein the VIC tubing is 13⅜″×9⅝″ and the VIT tubing is 6⅝″×4½″ VIT. 16 inch surface casing  31 , and a 20″ insulated conductor  30  will complete the well. The top will be cemented, and diesel will be used in the annulus (not shown). At the pay zone, the well deviates to be horizontal (not shown) and the 7″ slotted liner  35  allows steam injection into the pay. A production well can be similarly completed. As is shown, the dual VIT and VIC configuration is used at least through the permafrost zone (see dotted line). Thereafter, either single VIT or double VIT can be used, depending on the economics and reservoir needs. 
         [0062]    Exemplary tubing arrangements are found in  FIG. 4A-C .  FIG. 4A  shows a cut away of a dual VIT  41  and VIC  43  well in the permafrost region, each having a layer of vacuum  42 ,  44  respectively therebetween the double walls of the insulated pipes. Surface casing  46  contains the concentric double walled pipes, and a thermal barrier fluid  45 ,  47  is between the surface casing  46  and VIC layer  43 , and/or between the VIC  43  and VIT  47 . Thermal barrier fluid  45 ,  47  can be diesel, methane, cement, or any other suitable heat sink material. 
         [0063]      FIG. 4B  shows a single VIT  10  with vacuum layer  13 . Intermediate casing  17  surrounds the VIT  10  and a layer of methane gas  15  is therebetween. The well is completed with surface casing  19  and cement  21 ,  22 . 
         [0064]      FIG. 4C  shows a dual VIT  10  and VIC  25  with methane gas  15  therebetween, and each having a vacuum layer  13 ,  23 . Surface casing  27  and cement layers  21 ,  22  complete the well. 
         [0065]      FIG. 5A-B  shows the results of Thermal-Hydraulic Modeling studies conducting using C-FERS transient finite difference (FD) model, wherein the model features included temperature dependent thermal resistance for each annulus, fully dependent ground properties, including latent heat, and full thermo-hydraulics to update fluid temperatures along the permafrost region or the whole well. 
         [0066]    As can be seen in  FIG. 5B , the dual VIT and VIC casing was more effective that VIT casing alone ( FIG. 5A ), decreasing the thaw radius about 20-30% at 18 years. Further, the heat transfer was reduced to 0.02-0.05 BTU/ft·h·° F. (from interior of the inner string to the exterior of the outer string). Therefore, the modeling predicts that the method will be effective in reducing heat loss. TubeAlloy quotes a K value of 0.02 BTU/ft·h·° F. for the body of the tubing joint excluding the coupling. 
         [0067]    In  FIG. 6A-D  a well is shown in schematic. In  FIG. 6A  the couplings are aligned. See also detail at  FIG. 6C . In  FIG. 6B , the couplings are staggered, as in the detail at  FIG. 6D .  FIG. 7  shows a prior art well, using only a single VIT string. In  FIG. 8 , these three well types are modeled for heat loss, assuming three different levels of thermal conductivity (K). In the heat loss bar graphs it can be seen that decreasing the conductivity five fold has less effect on heat loss than doubling the vacuum tubing string and staggering the couplings. Since the estimated cost of the VIC is 3× the cost of typical casing, it is more cost effective to use dual vacuum tubing than to decrease the thermal conductivity significantly. 
         [0068]    The following documents are incorporated by reference in their entirety for all purposes:
   U.S. Pat. No. 3,397,745, Owens and Owens, “Vacuum-insulated steam-injection system for oil wells,” (1968);   U.S. Pat. No. 3,720,267, Allen, et al., “Well Production Method for Permafrost Zones” (1973);   U.S. Pat. No. 4,512,721, Ayres, et al., “Vacuum insulated stem injection tubing” (1985);   U.S. Pat. No. 7,677,272, Hickman and Cannon, “Insulator apparatus for vacuum insulated tubing” (2006); and   U.S. Pat. No. 7,854,236, Jibb, et al., “Vacuum insulated piping assembly method” (2008).