Patent Publication Number: US-11021915-B2

Title: Systems and methods for reducing the effect of borehole tortuosity on the deployment of a completion assembly

Description:
BACKGROUND OF THE DISCLOSURE 
     1. Field of the Disclosure 
     The present disclosure relates to subterranean developments, and more specifically, the disclosure relates to the deployment of completion assemblies within a subterranean well. 
     2. Description of the Related Art 
     In subterranean wells that are drilled to follow the structure of a subterranean formation, geo-steering can be used to maintain the trajectory of the wellbore within the zone where the fluids from the subterranean can be produced, known as the payzone. As a result of geo-steering, the wellbore can include a number of turns, curves, or doglegs, the cumulative effect of which can impede the successful subsequent running of the completion assembly. Completion assemblies being run through such a wellbore can become stuck or can be subject to sufficient bending or torsional stresses that the completion assembly becomes damaged or destroyed. 
     SUMMARY OF THE DISCLOSURE 
     Systems and methods of this disclosure can facilitate the running of the lower completion assemblies in deviated wells, horizontal wells, or wells with a number of doglegs. Embodiments of this disclosure are particularly well suited for subterranean wells that include an openhole screen based completion system. Screens generally cannot be rotated or significantly bent while being deployed and in reservoir sections where there has been geosteering there may be significant tortuosity in the well path. Embodiment of this disclosure can provide the balance between strength and flexibility which is required for the screens to pass by dogleg sections. Systems and method of this disclosure can alternately be utilized with any lower completion tubing based system that will be deployed in a well with a challenging well profile. The solution is not limited to screens only it will apply for conventional tubing and casing too 
     Systems and method described in this disclosure provide a flexible pipe joint that can reduce the overall impact of wellbore tortuosity due to the geo-steering of horizontal wellbores across production zones. The flexible pipe joint has sufficient flexibility to bend around a curve of the direction of the wellbore, yet strong enough to sufficiently withstand the forces of buckling while being run into the wellbore. The flexible pipe joint is sufficiently durable to last for the life of the well. Multiple flexible pipe joints can be placed in the completion assembly and optimally positioned within the completion assembly based on an engineering model or final post drilling survey. 
     In an embodiment of this disclosure, a completion system for running in a directional wellbore includes a plurality of tubular members mechanically secured in-line to form a production tubular. One or more isolation packers are positioned in-line with the tubular members. A lower completion guide is located at a downhole end of the production tubular. A hanger assembly is located at an uphole end of the production tubular. One or more of the tubular members includes a flexible pipe joint, the flexible pipe joint having: a base multilayered flexible tubular member; a first weave layer, the first weave layer being helically wrapped in a first direction around an outer diameter of the base multilayered flexible tubular member; a second weave layer, the second weave layer being helically wrapped in a second direction around an outer diameter of the first weave layer; and an outer tubular layer. 
     In alternate embodiments of this disclosure, the base multilayered flexible tubular member can include an inner liner member and a reinforcing member circumscribing the inner liner member. The completion system can include at least two of the flexible pipe joints. Each of the tubular members located between adjacent of the at least two of the flexible pipe joints can have a production screen. The first weave layer and the second weave layer can be formed of steel. 
     In an alternate embodiment of this disclosure, a completion system for running in a directional wellbore includes a plurality of tubular members mechanically secured in-line to form a production tubular, the production tubular positioned within the directional wellbore. One or more isolation packers is positioned in-line with the tubular members, the one or more isolation packers operable to form a seal with an inner diameter surface of the directional wellbore. A hanger assembly is located at an uphole end of the production tubular, the hanger assembly operable to support the production tubular within a casing. One or more of the tubular members includes a flexible pipe joint, the flexible pipe joint having: a base multilayered flexible tubular member; a first weave layer, the first weave layer being helically wrapped in a first direction around an outer diameter of the base multilayered flexible tubular member; a second weave layer, the second weave layer being helically wrapped in a second direction around an outer diameter of the first weave layer; and an outer tubular layer. The one or more of the tubular members are positioned along the production tubular at predetermined locations of maximum bending stress of the production tubular during the running in of the completion system in the directional wellbore. 
     In alternate embodiments, the base multilayered flexible tubular member can include an inner liner member and a reinforcing member circumscribing the inner liner member. The completion system can include at least two of the flexible pipe joints and each of the tubular members located between adjacent of the at least two of the flexible pipe joints can have a production screen. The first weave layer and the second weave layer can be formed of steel. 
     In another alternate embodiment of this disclosure, a method for running a completion system into a directional wellbore includes securing a plurality of tubular members mechanically in-line to form a production tubular and positioning one or more isolation packers in-line with the tubular members. A lower completion guide is provided at a downhole end of the production tubular. A hanger assembly is provided at an uphole end of the production tubular. One or more of the tubular members includes a flexible pipe joint, the flexible pipe joint having: a base multilayered flexible tubular member; a first weave layer, the first weave layer being helically wrapped in a first direction around an outer diameter of the base multilayered flexible tubular member; a second weave layer, the second weave layer being helically wrapped in a second direction around an outer diameter of the first weave layer; and an outer tubular layer. 
     In alternate embodiments, the base multilayered flexible tubular member includes an inner liner member and a reinforcing member circumscribing the inner liner member. The flexible pipe joint can be positioned along the production tubular at predetermined locations of maximum bending stress of the production tubular during the running in of the completion system in the directional wellbore. The directional wellbore can include a bend in a range of twelve to fifteen degrees. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the features, aspects and advantages of the embodiments of this disclosure, as well as others that will become apparent, are attained and can be understood in detail, a more particular description of the disclosure may be had by reference to the embodiments thereof that are illustrated in the drawings that form a part of this specification. It is to be noted, however, that the appended drawings illustrate only certain embodiments of the disclosure and are, therefore, not to be considered limiting of the disclosure&#39;s scope, for the disclosure may admit to other equally effective embodiments. 
         FIG. 1  is a section view of a subterranean well with a completion assembly in accordance with an embodiment of this disclosure. 
         FIG. 2  is a schematic diagram of an assembled flexible pipe joint in accordance with an embodiment of this disclosure. 
         FIGS. 3A-3E  are a schematic diagram of the separate layers of a flexible pipe joint in accordance with an embodiment of this disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The disclosure refers to particular features, including process or method steps. Those of skill in the art understand that the disclosure is not limited to or by the description of embodiments given in the specification. The subject matter of this disclosure is not restricted except only in the spirit of the specification and appended Claims. 
     Those of skill in the art also understand that the terminology used for describing particular embodiments does not limit the scope or breadth of the embodiments of the disclosure. In interpreting the specification and appended Claims, all terms should be interpreted in the broadest possible manner consistent with the context of each term. All technical and scientific terms used in the specification and appended Claims have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs unless defined otherwise. 
     As used in the Specification and appended Claims, the singular forms “a”, “an”, and “the” include plural references unless the context clearly indicates otherwise. 
     As used, the words “comprise,” “has,” “includes”, and all other grammatical variations are each intended to have an open, non-limiting meaning that does not exclude additional elements, components or steps. Embodiments of the present disclosure may suitably “comprise”, “consist” or “consist essentially of” the limiting features disclosed, and may be practiced in the absence of a limiting feature not disclosed. For example, it can be recognized by those skilled in the art that certain steps can be combined into a single step. 
     Where a range of values is provided in the Specification or in the appended Claims, it is understood that the interval encompasses each intervening value between the upper limit and the lower limit as well as the upper limit and the lower limit. The disclosure encompasses and bounds smaller ranges of the interval subject to any specific exclusion provided. 
     Where reference is made in the specification and appended Claims to a method comprising two or more defined steps, the defined steps can be carried out in any order or simultaneously except where the context excludes that possibility. 
     Looking at  FIG. 1 , subterranean well  10  can have wellbore  12  that extends to an earth&#39;s surface  14 . Subterranean well  10  can be an offshore well or a land based well and can be used for producing hydrocarbons from subterranean hydrocarbon reservoirs. Wellbore  12  can be drilled from surface  14  and into reservoir  16 . Reservoir  16  can be a layered reservoir that follows an irregular or meandering path. Geo-steering can be used to direct the drilling of wellbore  12  so that wellbore  12  passes through various layered formations and follows the path of reservoir  16 . 
     A portion of the length of wellbore  12  can be lined with inner casing  20  and outer casing  22 . Another portion of the length of wellbore  12  can be an uncased or open hole region  24  of wellbore  12 . Completion system  26  can extend from inner casing  20  and into open hole region  24  of wellbore  12 . 
     Completion system  26  can be a lower completion system that is set adjacent to reservoir  16 . Completion system  26  can be anchored to inner casing  20  with hanger assembly  28 . Hanger assembly  28  is located at an uphole end of completion system  26  and supports completion system  26  within inner casing  20  in a known manner. 
     Completion system  26  includes a plurality of tubular members  30  mechanically secured in-line to form production tubular  32 . Production tubular can have a diameter for example, in a range of 2 and ⅞ inches to 18 and ⅝ inches. Production tubular  32  extends from hanger assembly  28  to lower completion guide  34  so that hanger assembly  28  is located at an uphole end of production tubular  32  and lower completion guide  34  is located at a downhole end of production tubular  32 . Lower completion guide  34  can be threaded or otherwise connected to the downhole end of production tubular  32  and can have a rounded end profile to assist in guiding completion system  26  into and through wellbore  12 . 
     Completion system  26  can also include one or more isolation packers  36  positioned in-line with tubular members  30 . Isolation packer  36  can be in a deflated state while running completion system  26  and can be inflated or expanded when completion system  26  has landed in order to form a seal with an inner diameter surface of wellbore  12 . Isolation packer  36  can be used to prevent fluids in one region of wellbore  12  from traveling past isolation packer  36  to another region of wellbore  12 . 
     Tubular member  30  can also include production screens  38 . Production screens  38  can control the amount of sand entering completion system  26  while allowing production fluids from reservoir  16  to enter completion system  26 . Maximizing the number of production screens  38  can maximize the productivity of subterranean well  10 . By reducing a stiffness of completion system  26  with flexible pipe joint  40 , production screens  38  can be deployed in increasingly tortuous well profiles, such as those resulting from geo-steering. 
     One or more of tubular members  30  can be flexible pipe joint  40  that is secured in-line with adjacent tubular members  30 . As an example, flexible pipe joint  40  can be threaded or otherwise connected to adjacent tubular members  30 . 
     Looking at  FIG. 2 , in an example embodiment flexible pipe joint  40  can include base tubular member  42 . Base tubular member  42  can be a base multilayered flexible tubular member and include inner liner member  44 . Inner liner member  44  can define an inner diameter bore of flexible pipe joint  40 . Base tubular member  42  and inner liner member  44  can be formed of, for example, steel such as steel used to form oil country tubular goods. Alternately, base tubular member  42  and inner liner member  44  can be formed of an austenitic nickel-chromium-based super alloy, such as Inconel® (a registered mark of Special Metals Corporation). 
     One or more reinforcing members can circumscribe base tubular member  42 . As an example, reinforcing members can include one of, or a combination of, pressure sheath  46 , pressure vault  48 , and armor layer  50 . In the embodiment of  FIG. 2 , two separate armor layers  50  are included. One or more intermediate sheath or tensile layers  52  can be located adjacent to reinforcing members. 
     Flexible pipe joint  40  can further include external sheath  54  as an outer tubular layer. External sheath  54  is an outermost member of flexible pipe joint  40  and defines an outer diameter surface of flexible pipe joint  40 . External sheath  54  can be made from a light, highly flexible and high strength alloy, alone or in combination. 
     Flexible pipe joint  40  further includes first weave layer  56  and second weave layer  58 . First weave layer  56  is helically wrapped in a first direction around an outer diameter of base tubular member  42  and second weave layer  58  is helically wrapped in a second direction around base tubular member  42 . First weave layer  56  and second weave layer  58  can be formed of, for example, steel such as steel used to form oil country tubular goods. In alternate embodiments, first weave layer  56  and second weave layer  58  can be formed of a nickel-chromium-based super alloy such as Inconel® (a registered mark of Special Metals Corporation), or an iron based superalloy. In other alternate embodiments first weave layer  56  and second weave layer  58 , can be formed of other materials that exhibit high strength and ductility, mechanical strength, resistance to thermal creep deformation, good surface stability, and resistance to corrosion or oxidation. 
     The flexibility of the combination of first weave layer  56  and second weave layer  58  is not derived from the material used to form first weave layer  56  and second weave layer  58 , but from the helical and oppositely directed weave of first weave layer  56  and second weave layer  58 . Additional yield strength can be provided by including tensile layer  52  between first weave layer  56  and second weave layer  58 . When the flexible pipe joint  40  is loaded in axial tension, a compressive strain can be generated in first weave layer  56  and second weave layer  58 , resulting in an inward radial displacement. When flexible pipe joint  40  is loaded with pressure, the squeezing or ballooning of flexible pipe joint  40  can produce a corresponding change of axial length of flexible pipe joint  40 . Flexible pipe joint  40  should exhibit elastic stress-strain behavior. With elastic stress-strain behavior the stress and strain are linearly related by a constant of proportionality. When flexible pipe joint  40  is loaded elastically and then unloaded, flexible pipe joint  40  will return to the original dimensions of flexible pipe joint  40  and there will be no permanent, residual stress or strain left over in flexible pipe joint  40 . 
     First weave layer  56  and second weave layer  58  provide anti-buckling features to flexible pipe joint  40 . Because first weave layer  56  and second weave layer  58  are wound in opposite directions, any bending and buckling forces counter each other with the combination of first weave layer  56  and second weave layer  58 , providing a range of movement which is defined by the density of the wraps per linear foot of first weave layer  56  and second weave layer  58 . Therefore the combination of first weave layer  56  and second weave layer  58  will prevent excessive torsion and bending that could otherwise damage or destroy flexible pipe joint  40 . However, flexible pipe joint  40  will retain sufficient flexibility to be run into wellbore  12 , which can include changes in direction of up to fifteen degrees and will maintain sufficient strength to withstand the forces required to run completion system  26  into wellbore  12 . 
     Using software simulation, it was shown that including first weave layer  56  and second weave layer  58  in flexible pipe joint  40  can provide a 50% increase in the torsion flexibility of pipe joint  40 , and a 50% reduction in side forces undergone by flexible pipe joint  40  compared to a joint that does not include first weave layer  56  and second weave layer  58  but is otherwise similar. The range and magnitude of side forces that a typical completion system can undergo will be dependent on the tortuosity of the wellbore and will vary from well to well depending on the well profile that was drilled. 
     Looking at  FIGS. 3A-3E , in order to form flexible pipe joint  40 , first weave layer  56  ( FIG. 3A ) and second weave layer  58  ( FIG. 3B ) can be separately formed. First weave layer  56  and second weave layer  58  are self-supporting in that first weave layer  56  and second weave layer  58  can retain a helical shape without external support, while the pressure integrity and tensile strength are provided by other layers of flexible pipe joint  40 . Base tubular member  42  and external sheath  54  can be provided separate from first weave layer  56  and second weave layer  58  ( FIG. 3C ). First weave layer  56  and second weave layer  58  can then be combined together ( FIG. 3D ). The combined first weave layer  56  and second weave layer  58  can then be positioned radially outward of base tubular member  42  and radially inward of external sheath  54  to form flexible pipe joint  40  ( FIG. 3E ). 
     In an example of operation, wellbore  12  can be drilled using known geo-steering techniques to follow a desired path. After drilling operations are complete, an engineering model or final survey of wellbore  12  and completion system  26  can be used to determine the arrangement of the components of completion system  26 . In certain embodiments there can be at least two flexible pipe joints  40 . In order to maximize the amount of amount of production screens  38 , each tubular member  30  located between adjacent of the at least two of the flexible pipe joints  40  has a production screen  38 . 
     The number and position of flexible pipe joints  40  can be determined by such engineering model or final survey. As an example, flexible pipe joints  40  can be located along completion system  26  at locations where the highest anticipated bending stresses are anticipated during the running of completion system  26  into wellbore  12 , such as at the locations of bends of wellbore  12  of twelve to fifteen degrees. After running completion system  26  into wellbore  12 , the isolation packers  36  can be inflated or expanded when completion system  26  has landed in order to form a seal with an inner diameter surface of wellbore  12  and hydrocarbons or other fluids from reservoir  16  can enter completion string  26  through production screen  38  for delivery to the surface. 
     Embodiments described in this disclosure therefore provide systems and methods that include a flexible pipe joint that is both flexible, can resist sinusoidal and helical buckling, and can safely transmit the compressive forces applied during the running of the completion system into the wellbore. Such a flexible joint can allow for a wellbore to be drilled using geo-steering technology to follow an optimal path along and through a reservoir and therefore allow more exposure of the wellbore to the payzone, with reduced concerns for such a path leading to sticking, damage, or destruction of the completion assembly. 
     Systems and methods of this disclosure therefore allow operators to provide a wellbore that maximizes reservoir contact to maximize production from the reservoir. In addition, embodiments of this disclosure allow for an increase in the number of production screens that can be made part of the completion assembly, compared to currently available systems. 
     Embodiments of this disclosure, therefore, are well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others that are inherent. While embodiments of the disclosure has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present disclosure and the scope of the appended claims.