EP2820338B1 - Hochdruck-leitungssystem für grosses bohrloch - Google Patents

Hochdruck-leitungssystem für grosses bohrloch Download PDF

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Publication number
EP2820338B1
EP2820338B1 EP13793591.2A EP13793591A EP2820338B1 EP 2820338 B1 EP2820338 B1 EP 2820338B1 EP 13793591 A EP13793591 A EP 13793591A EP 2820338 B1 EP2820338 B1 EP 2820338B1
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EP
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Prior art keywords
conduit
well
conduits
bore
subterranean
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EP13793591.2A
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English (en)
French (fr)
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EP2820338A4 (de
EP2820338A1 (de
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Bruce A. Tunget
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TUNGET, BRUCE A.
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Individual
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Priority claimed from GB1203649.7A external-priority patent/GB2514075B/en
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0035—Apparatus or methods for multilateral well technology, e.g. for the completion of or workover on wells with one or more lateral branches
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/18—Pipes provided with plural fluid passages
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • E21B23/12—Tool diverters
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/04—Casing heads; Suspending casings or tubings in well heads
    • E21B33/047—Casing heads; Suspending casings or tubings in well heads for plural tubing strings
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/02—Subsoil filtering
    • E21B43/10—Setting of casings, screens, liners or the like in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/14—Obtaining from a multiple-zone well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/01—Sealings characterised by their shape

Definitions

  • conduits of the well conduit system include radial loading surfaces for abutting one conduit to another and comprise continuous elastically compressible and expandable pipe body circumferences, wherein the effective diameter of one conduit is greater than the other for forming a containment system that is able to contain higher pressures than conventionally installed conduits of the same size.
  • subterranean apparatuses e.g. separators, heat exchangers, side-track side pocket whipstocks and other apparatuses usable for extracting and processing injectable and producible fluids from one or more wells, in a more efficient and/or environmentally conscious manner than is currently practiced.
  • Embodiments of the present well conduit system can communicate fluids through large diameter, higher-pressure, conduit containment to provide significant pressure bearing improvement over conventional well designs, which can include the well designs of the present inventor, as disclosed in United Kingdom Patent GB2465478B entitled “Apparatus And Methods For Operating A Plurality Of Wells Through A Single Bore".
  • the present inventor's apparatus and methods of use as disclosed in United Kingdom Patent GB2471760B entitled “Apparatus And Methods For Subterranean Downhole Cutting Displacement, And Sealing Operations Using Cable Conveyance,” may be used within the well conduit systems and methods of the present invention for maintenance, boring via side-pockets, and/or abandonment.
  • embodiments of the present invention may utilise the teachings of the systems and methods disclosed in UK Patent Application GB1021787.5 , entitled “Managed Pressure Conduit Systems And Methods For Boring And Placing Conduits Within The Subterranean Strata,” published under GB2475626A on 25 May 2011 , for particular uses.
  • the present invention can provide significant and distinctive improvements over the teachings of existing systems and methods.
  • conventional systems and methods are described in Yang et al., in Chinese Patent Application CN102226378A , entitled “Reinforced Riser Pipe Combined Structure And Construction Method;” Morgan and Sinclair in U.S. Patent Application No. US 2011/0068574 A1, published 24 March 2011 entitled “Pipe Connector Device;” Gallagher and Lumsden in U.S. Patent 5,954,374 entitled “Pipe Connectors,” filed 18 April, 1997 and issued 21 September, 1999; Bilderbeek and Hendrie in U.S.
  • Patent Number US 7,740, 061 B2 entitled “Externally Activated Seal System For Wellhead,” filed 24 September, 2007 and issued 22 June, 2010; Cook et al. in U.S. Patent U.S. 7,147,053 B2, filed 13 August, 2004 and issued 12 December 2006, entitled “Wellhead:” Berg et al. in U.S. Patent No. 6,698,610 B2 , entitled “Triple Walled Underground Storage Tank,” filed 28 February, 2002 and issued 02 March, 2004;” Berg, Sr. in U.S. Patent No. 6,820,762 B2, filed 07 January, 2002 and issued 23 November 2004, entitled "High Strength Rig For Storage Tanks;” Wright, et al. in U.S. Patent No.
  • Yang et al discloses ribbed reinforcement of an internal conduit that is loosely placed and cemented within an outer conduit (e.g., loosely-placed T-shaped ribs that are frictionally unsuitable for adjoining long pipe bodies since the weakest point, which is the rib of the T-shape, is subject to plastic deformation and failure if subjected to forces used in the present systems and methods).
  • embodiments usable within the scope of the present disclosure utilize the abutment of radial loading surfaces and conduits that may be elastically expanded and compressed during installation using hoop forces, wherein the release of the hoop forces causes the release of the elastic memory of the conduits' pipe bodies, which adjoins one pipe body to the other.
  • Hoop stress conduit joint connectors are disclosed in Morgan and Sinclair, and Gallagher and Lumsden, which due to their high cost of manufacture, as compared to screwed and coupled connections, are not widely used in most conventional well designs.
  • Morgan et al describes large diameter high-pressure connectors, with exceedingly tight machining tolerances.
  • Embodiments usable within the scope of the present disclosure can, conversely, enable the application and use of lower-cost, hoop stress strengthening between pipe body walls.
  • Cook, et al. describes the expansion of conventional sized tubular conduits within a conventional sized wellhead, where "each inner casing is supported by intimate direct contact pressure between an outer surface of the inner casing and an inner surface of the outer casing.”
  • the Cook, et al., wellhead includes a conventionally sized well design, e.g., "generally to well bore casings, and in particular to well bore casings that are formed using expandable tubing.”
  • a conventionally sized well design e.g., "generally to well bore casings, and in particular to well bore casings that are formed using expandable tubing.”
  • teachings are restricted to the maximum conventional rotary table diameter of 49.5 inches (124.25 cm), despite its growing obsolescence with the advent of top drives.
  • Cook, et al. teaches a "telescoping effect" for solid conduits that cannot accommodate the use of hoop stress sharing, as described herein.
  • Cook, et al. also teaches the use of higher yield strength materials to increase pressure integrity, which is a conventional alternative to embodiments of the present disclosure, which include hoop stress sharing.
  • a pipe body having an outer diameter of 122 centimetre (cm) (48 inches), having a material with a yield of 275.8 newtons per millimetre squared (N/mm2) (40,000 psi), a wall thickness of 5.7 cm (2.25 inches), can be combined with a conduit formed from the same grade of material and having an outer diameter of 137 cm (54 inches) and a wall thickness of 5.7 cm (2.25 inches).
  • a high compression strength cement can be placed within the annulus between the two pipe bodies and radial extending load surfaces, to enable the sharing of the hoop stress resistance between the pipe bodies.
  • This arrangement may, in combination, form an effective wall thickness of 0.133 cm (5.25 inches), which can comprise an outside diameter of 137cm (54 inches), and which is capable of supporting 469.2 bar (6800 psi) of internal yield pressure and 484.1 bar (7000 psi) of collapse pressure, according to a standard API bulletin 5C3 calculation. If a 930.8 N/mm2 (135,000 psi) yield material is used, the internal yield pressure, or burst pressure, can increase to 1583.6 bar (22,960 psi), and the collapse pressure can increase to 1633.9 bar (23,690 psi) with the API 5C3 calculation.
  • Berg et al. and Berg Sr. relate to shallow tanks for service stations that store already-processed hydrocarbons, and do not relate to use with subterranean tanks engaged to a wellhead or usable for processing subterranean deposits.
  • processing apparatuses e.g., separators and heat exchangers.
  • the pressure experienced within shallow subterranean storage tanks for already-processed hydrocarbons, which are not connected to high pressure and large volumetric hydrocarbon reservoirs are relatively insignificant when compared to, as described above, the required burst and collapse pressures associated with well construction and operation.
  • embodiments useable within the scope of the present disclosure can enable integration of apparatuses and methods of the present inventor, e.g., chamber junctions, bore selectors and manifold crossovers, also allow selective access and configuration of downhole processing and separation equipment for the purposes of, e.g., maintenance, repair and fluid production and/or injection communication with subterranean deposits, water floods or other subsurface fluid horizons through axially concentric or autonomous conduits and wellhead connections.
  • Sizer and Brown disclose systems which are conventionally usable for a limited range of substantially water or substantially hydrocarbon wells, due to the lack of a large diameter, high pressure, containment system for completion equipment that can be usable for producing hydrocarbons and/or water from the strata through the well bore.
  • embodiments usable within the scope of the present disclosure can provide more space within a well conduit system, wherein apparatus and methods of the present inventor, such as those described in WO2011/119198A1 , GB2479432 , WO2011/119197A1 and GB2479043A , can be combinable with the present embodiments to provide concentric conduit configurations and, thus, provide significant improvement over smaller and less efficient autonomous, parallel arrangements, used within conventionally sized wells.
  • Argumugam, et al., Jackson, et al., Dinning, ring, Roth, et al., and Pratt generally relate to kick-over-tools for side-pocket mandrels that are used in relatively small hole sizes for placement of various flow apparatuses, but are not designed for side-tracking of wells with a drill string.
  • Embodiments of the present invention can be used with the teachings of the present inventor described in GB2471760B and GB2475626A for rotatably placing and cementing larger bore conduit and manifold strings usable with a fluid mixture, or heavyweight drilling fluid slurry, wherein the installed conduits, crossovers and manifold strings may be temporarily hung from a wellhead to provide a flow passageway, using an olive arrangement, during well formation, or they can be adapted for use after well formation, with substantially hydrocarbon or substantially water fluids
  • API Guidance Document HF1 entitled “Hydraulic Fracturing Operations - Well Construction and Integrity Guidelines ,” also published on the same website at the time of this filing.
  • Embodiments usable within the scope of the present disclosure can be combined and/or used with apparatuses of the present inventor, as described in UK Patent 2471385 , entitled “Apparatus And Methods For Forming And Using Subterranean Salt Cavern,” which teaches improvements in fluidly accessing a salt deposit, wherein relatively large bores are conventionally practiced, albeit without the significant pressure bearing improvements of the present embodiments.
  • ENI believes that improvements in well recovery factors have a positive environmental effect, e.g., the reduction of greenhouse gases, because increases in the recovery rate allow for added hydrocarbon production without having to employ additional land, exploit additional resources (water/energy), or produce polluting by-products (acid gases).
  • ENI further states that "[I]t becomes fundamental to exploit the most advanced drilling and development techniques, as well as recovery processes, whether exploiting those of Improved Oil Recovery (injecting water or gas to maintain the original pressure level inside the reservoir), or Enhanced Oil Recovery (injecting steam, polymer solutions, natural gas or carbon dioxide), and also to adopt 'intelligent systems' (smart fields) for the real-time optimization of production activities.”
  • Well construction may vary according to geologic, environmental and operational settings, but the basic practices in constructing a conventional well are similar, wherein the vast majority involve the placement of concentric conduits within a single well bore, e.g., having a conductor or intermediate casing with a concentric outside diameter of 76.2 cm (30 inches) and/or a diameter of 50.8 cm (20 inches) and/or a diameter of 34 cm (13 3/8") surrounding a production casing having a diameter of 24.45 cm (9 5/8 inches).
  • a production liner e.g., having a diameter ranging from 11.4 cm (4.5 inches) to 17.8 cm (7 inches
  • injection and/or production tubing sized between 6 cm (2 3/8 inches) to 14 cm (5.5 inches).
  • Pressure maintenance is important because the integrity of the subterranean strata may degrade with pressure depletion and the loss of pressure support may result in, e.g., subsidence within the strata and potentially at surface if the overburden does not bridge across depleted subterranean strata.
  • water injection or flooding of the subterranean strata directly below a deposit may provide pressure support for production and potentially prevent subsidence, shale, clay and other formation types may react with the injected water to also cause strata instability around the production and/or injection zone.
  • instability within the strata may prevent future drilling through subterranean strata affected by this instability, and the ability to place well bores for future production may be lost.
  • a salt production deposit e.g., solution mining salt deposit, geothermal steam deposit, and/or substantially hydrocarbon deposits from initial completion of a well to reduce the risk of strata subsidence and instability preventing future drilling.
  • the present state-of-the-art for low cost recovery well designs, apparatuses and methods is such that standardization not only applies to concentric single bore well designs, apparatuses and methods practiced, but also to upstream hydrocarbon exploration, extraction, and well site processing. Standardization also applies to disciplines within the art, if not the practitioners, themselves, who develop specialized skills in segregated silos of drilling, completion and production, wherein mastering the art does not necessarily involve mastering sets of skills across the combined arts of drilling, completion and production, but rather mastering the methods and apparatus within each silo, using a standard set of methods with standard sized apparatus. Such silos, and the compartmentalized thought process within each, may prevent larger efficiency gains that require stepping across conventional boundaries of practice and art, or out-of-the-box. As such, a need exists for systems and methods usable to overcome boundaries to changing the conventional bore hole and conduit sizes upon which the entire industry has been built.
  • Standardization of apparatuses within industry is so prevalent that even when equipment no longer provides a primary function, e.g., when the rotary table of a drilling rig is made obsolete by the installation of a top drive, its size is maintained below a 49.5 inch standard diameter. While historic versions of a kelly and kelly bushing rotary table are still used today, for various reasons, standardization of such relatively obsolete equipment is suboptimal when, e.g., larger diameter conduits and wellheads could be installed more easily using a rig's derrick, if the diameter of an obsolete rotary table is increased.
  • fracturing fluids may carry toxic and/or explosive chemicals, e.g., low friction proppant fracturing fluids and/or propane fracturing fluids comprising natural incendiary hydrocarbons.
  • subterranean zonal isolation may comprise blowout preventers, and a drilling slurry or mud, during construction with casing installation and cementation of the casing, within the subterranean strata, and cap rock containing producible or injectable strata horizons after well construction.
  • Construction of a well using conventional design generally comprises sequentially drilling and placing successive casings, wherein mitigations often involve installation of additional casing strings during drilling. Additionally, well designs generally include contingency options to increase the reasonable probability of successfully extending a well bore to the targeted deposit while mitigating or eliminating the risk of unplanned releases of injected or produced fluids, or the failure to complete a well due to unplanned events.
  • Drilling of a well generally comprises using a rotated drilling string to bore a passageway for placement of casings using a drilling fluid, generally comprising a mixture of water, clays, fluid loss control additives, density control additives, and viscosifiers, which is circulated to remove the formation cuttings, maintain pressure control of the well and stabilize the bore hole wall.
  • a drilling fluid generally comprising a mixture of water, clays, fluid loss control additives, density control additives, and viscosifiers, which is circulated to remove the formation cuttings, maintain pressure control of the well and stabilize the bore hole wall.
  • well construction fluids e.g., drilling mud that may require increases in weight as drilling progresses deeper, and wherein better well control of deeper and higher pressure formations due to the loss of the hydrostatic pressure well barrier of the drilling mud is needed.
  • the installation of a conductor pipe or casing may include driving it into place with a large hammer, like structural pilings, or a bore may be drilled for its installation, wherein the conductor may have a wellhead at its upper end, and whereby the conductor or casing provides a stable bore for a subsequent boring and casings.
  • constructing a subterranean well generally comprises several cycles of drilling or boring into the subterranean strata, placing steel pipes or conduits (e.g., casing), and cementing the lower end of said casing in place to provide well bore stability and isolation of the surface environment and intermediate formations from subterranean pressures.
  • Each cycle of boring, casing and cementing places a steel protecting lining in sequentially smaller sizes to fit within the inside diameter of the previously installed casing.
  • This critical part of well construction provides zonal isolation between different formations, including isolation of groundwater horizons, and provides structural support of the well, wherein said cement is fundamental in maintaining integrity throughout the life of the well and forms a part of corrosion protection.
  • the surface hole is drilled and the surface casing is run into the hole and cemented in place.
  • One of the main purposes of the conductor or surface casing may be to protect (through isolation) groundwater aquifers. Given its importance, the conductor and surface casing may be regulated by governmental agencies and engineering requirements to a predetermined depth based upon the deepest groundwater resources and pressure control requirements of subsequent drilling operations.
  • Production tubing is often sized to facilitate improved liquid or gas handling, wherein huff-and-puff operations for intermediately sized tubing may be economic.
  • the salt cavern gas storage industry uses simultaneous liquid flow streams for solution mining and one-time dual flow streams for dewatering gas caverns
  • the upstream hydrocarbon upstream industry does not use dual flow streams, albeit in limited forms of gas lift and jet pump arrangements.
  • the embodiments of the present invention relate, generally, to well conduit systems (1) and methods usable to form and to maintain one or more passageways through the subterranean strata below a wellhead assembly (10).
  • conduits of the well conduit system (1) can have a diameter larger than what is conventionally practiced for forming a containment system that is able to contain higher pressures than conventionally installed conduits of the same size.
  • the claimed invention provides a well conduit system as defined in claim 1 and a method of using a well conduit system as defined in claim 19.
  • Embodiments of said well conduit system comprise a first (2) and at least one second (3) conduits with continuous elastically compressible inner and elastically expandable outer pipe bodies (4).
  • a plurality of intermediate radial loading surfaces (5, 6, 41, 42, 49, 123) can extend across an annulus and radially between at least two of the circumferentially elastic conduit walls to form an abutment with an adjacent circumferential conduit wall, to define the at least one concentric annular space (7) therebetween.
  • the abutment of the radial loading surfaces against an adjacent conduit wall adjoins one pipe body to another pipe body, so as to share hoop stress resistances (8) through said abutment.
  • one of said pipe bodies abuts to another by compressing the circumferentially elastic larger diameter of the inner pipe body and expanding the circumferentially elastic smaller diameter of the outer pipe body, using a hoop force to insert the larger effective diameter inner pipe body within the smaller diameter outer pipe body.
  • embodiments of the present invention can control fluid communication through said one or more passageways between injectable or producible strata and at least one wellhead assembly (10), secured to the upper end of said first and at least one second conduits, forming said one or more passageways through the subterranean strata.
  • Embodiments of the conduit system (1) can provide additional space to, e.g., provide additional conduit strings and/or use proven off-the-shelf isolation methods and apparatuses within the higher pressure containment system formed, wherein the pressure ratings of larger bore conduits may approach those of smaller bore conduits by sharing hoop stress resistances between a first and at least one or more second large diameter conduits.
  • Various embodiments may use radial loading surfaces comprising part of at least one elastically compressible inner or elastically expandable outer pipe body (4) circumference wall, for example the embodiments depicted in Figures 7 , 13 , 18-20 , 34-37 , 50-61 .
  • Various other embodiments may use independent bearings intermediate to compressible inner and expandable outer pipe body circumference walls, e.g. those shown in Figures 9-12 , 21-28 , 30-31 and 33 .
  • radial loading surfaces comprising a partially plastic deformable portion, e.g., those described in Figures 12, 12A, 13 and 18-20 , and/or an elastically expandable portion to provide abutment and to share hoop stress resistances (8) between first and at least one or more second conduits.
  • Any form of deformable material is usable (e.g. metal, elastomers, swellable materials), to support the abutment of radial loading surfaces during or after installation.
  • malleable metals, elastomers and/or swellable materials may significantly aid placement of additional conduits (3) and the overall efficiency of the effective wall thickness (9) and, thus, the load bearing capacity of the well conduit system (1).
  • Embodiments of the large diameter, high pressure conduit system may incorporate virtually any technology developed for smaller diameter, high pressure axially concentric or axially autonomous conduits, e.g., dual bore trees engaged to a dual bore wellhead to provide dual well bores.
  • a plurality of said high pressure wells may be constructed for simultaneous production and/or injection within the higher pressure bearing walls of a single main bore comprising a large diameter high pressure conduit system.
  • Embodiments of the present invention minimize the need to deviate from conventional standardization, wherein, e.g., the introduction of large diameter, high-pressure conduit systems may not require the removal of the rotary table for drilling operations, albeit the rotary table could be temporarily removed for placement of conduits and large apparatuses, and then replaced for drilling.
  • Significant efficiencies may be realized if, e.g., the conventional restriction of passing conduits and equipment, larger than a standard size rotary table, through the rig floor substructure is removed, but it is not a requirement, since large diameter conduits may be conventionally keelhauled beneath the drill floor substructure for subterranean placement.
  • a conventional rig may have sufficient room to place a 91.4 cm (36") to 106.7 cm (42") outside diameter conduit or apparatus, depending on rig design, using its derrick, drawworks and blocks.
  • the substructure of the rig is modified, the placement of much larger conduits and apparatuses, e.g.
  • Embodied large diameter, high-pressure conduit systems can be used to provide additional conduit strings to, e.g., construct wells in very deep water, where fracture gradients are very low and/or very deep wells where larger bores may retain hole diameters for the industry preferred reservoir hole size of 21.6 cm (8 1 ⁇ 2) inch boreholes.
  • Various embodiments may be used to provide a plurality of lower end 21.6 cm (8 1/2 inch) well bores into a reservoir or subterranean deposit through a single high pressure conduit, which may also be usable to, e.g., provide a subterranean vertical separator to process produced and/or injected fluids.
  • Hoop forces comprising gravity, mechanical (38), pneumatic (39) and/or hydraulic (40) forces; e.g., the embodiments depicted in Figures 27-32 .
  • Hoop forces may comprise, e.g., physically hammering or pushing one pipe body into another with mechanical, pneumatic and/or hydraulic forces, e.g., the embodiments illustrated in Figures 21-26 , 33 , 50-54 , 60-61 , 84-106 and 113-123 , and/or by using hydraulic forces, such as the embodiments shown in Figures 34-36 , 50-54 , 60-61 , 84-106 and 113-123 .
  • Various embodiments can comprise a wellhead assembly (10), e.g. the embodiments shown in Figures 5-7 , 14-15 , 17-20 , 23 , 26 , 33-34 and 50-54 , with at least one fluid communication conduit hanger spool (14) subassembly, engaged with securable (15) and sealable (16) components to first (17) and at least one second (18) conduit head subassemblies associated with, and secured to, the upper end of first (2) and at least one second (3) conduits.
  • the one or more spool (14) subassemblies can be engaged at the upper end of the first and at least one second conduits or between the first and at least one second conduit head subassemblies to form the wellhead assembly.
  • inventions may comprise substantially concentric (35), axially autonomous (34) and/or transitions between concentric and axially autonomous (47) conduits, e.g., the embodiments illustrated in Figures 14-15 , 17 , 45-48 , 55-61 , 69-72 , 82-83 , 76-118 and 120-132 , extending axially downward between at least one wellhead assembly and the lower end of one or more wells.
  • Various conduit transitions, between concentric and axially autonomous (47) passageways may minimize fluid friction and erosion fluid flowing forces, with their diameters and gradual angular transition, e.g. the embodiments shown in Figures 106-108 , or their angular transition may occur within a shorter axial distance if fluid flowing forces and/or erosion are less significant, such as the embodiments shown in Figures 109-112 .
  • Axially concentric (35) and axially autonomous (34) embodiments of the present invention can be used for any simultaneous flow stream application, e.g. larger bore conduits may initially be used for production until water production causes a switch to higher velocity annular flow or axially autonomous flow velocities, thereby providing the ability to switch between maximum production and velocity production conduits, or, e.g., to allow collection within a tank (13), injection, and/or processing and re-use, of fracturing fluids used during well construction.
  • Embodiments (49) of the present invention can use a plurality of concurrently weight set mechanical and/or hydraulically axially urged engagable and axially parallel associated autonomous conduit (34) snap connectors, with elastically compressible and expandable circumferences (4A) associated with said pipe body (4) circumferences to, in use, connect a plurality composite joints of substantially concentric (35) and/or axially autonomous (34) disposition, as shown in the embodiments of Figures 50-54 , 58-61 , 76-105 , 113-118 and 122-125 .
  • inventions may be comprised of autonomous or connecting inner passageways, annular passageways and/or lateral (194) passageways, e.g., the embodiments shown in Figures 34-36 , 50-54 , 60-75 , 84-86 and 93-105 , for controlling fluid communication.
  • Still other embodiments may comprise one or more manifold crossovers (20), e.g., the embodiments depicted in Figures 62-75 , 84-86 and 93-105 , chamber junctions (21) and/or side-pocket whipstock (48), e.g.
  • valves (24) and/or diverting apparatuses (25) may control apparatus placement and fluid communication; e.g., the embodiments shown in Figures 6-7 , 14 , 17 , 60-61 , 65-68 , 73-75 , 93-105 , 119 , 119A-119E , 122-123 and 128-132 .
  • Selective placement of downhole apparatus within one or more passageways, extending downward from a wellhead or inner passageway, may use a bore selector (32) and/or kick-over tool (33K) which are usable to control apparatus and fluid communication through manifold crossovers, chamber junctions and/or side pocket whipstocks.
  • a bore selector (32) and/or kick-over tool (33K) which are usable to control apparatus and fluid communication through manifold crossovers, chamber junctions and/or side pocket whipstocks.
  • a side pocket (33) comprising a conduit body (48) with upper and lower ends and an axially autonomous (34) bore (199) side pocket formed between said ends on the inside diameter of said conduit, with said axially autonomous bore being usable for urging a strata passage and hanging a protective metal lining across said strata passageway, with said autonomous bore extending axially downward and laterally outward from a lower end whipstock (46) to exit the outside diameter of the conduit system at an axial inclination.
  • the axis of said autonomous bore can be axially and laterally offset from the through passage (198) of the conduit system such that the upper end of said autonomous bore is below the upper end of the containing conduit for engagement with a kick-over tool usable to access said autonomous bore from said through passageway, as illustrated in the embodiments of Figures 113-118 and 120-132 .
  • FIG. 12 can use a bore selector tool (32) and/or kick-over tool (33K), e.g. the embodiments illustrated in Figures 122-124 and 128-132 , to selectively access the exit bores of a chamber junction to place valves (24) and/or diverting apparatuses (25) within a plurality of wells.
  • a bore selector tool (32) and/or kick-over tool (33K) e.g. the embodiments illustrated in Figures 122-124 and 128-132 , to selectively access the exit bores of a chamber junction to place valves (24) and/or diverting apparatuses (25) within a plurality of wells.
  • a kick-over tool comprising a tool for placing or retrieving well equipment via a through passage (198) of a conduit adjacent to a side-pocket whipstock lateral bore (199), wherein said kick-over tool may comprise an elongate body (197) with an arm (195) that can be movable with said body and/or axially rotatable from a pivot point (196) on said elongate body.
  • a first running and retrieving position and a second position for using said arm to place or retrieve equipment, to and from the lateral bore of a side-pocket whipstock can be achieved by placing and retrieving the kick-over tool in the first position and using the second position to engage the upper end of the elongate body proximally to the selected lateral bore, so as to divert said equipment to and from said lateral bore with said movable arm, as illustrated in the embodiments of Figures 113-118 and 120-132 .
  • Various embodiments may comprise at least one boring assembly axial lower end (45) and/or axial and lateral whip-stock (46, 48) orifice within substantially concentric (35) or axially autonomous (34) conduits for boring strata and placing conduits within said strata and well conduit system, e.g., the embodiments shown in Figures 87-90 , and 120-132 .
  • inventions may comprise a subterranean fluid processing tank (13), e.g., the embodiments illustrated in Figures 17 , 60-61 and 93-105 , which may be formed within and between the wellhead and the lower end of the first and at least one second conduits so as to surround and fluidly communicate with one or more well passageways of the well conduit system.
  • a subterranean fluid processing tank 13
  • the embodiments illustrated in Figures 17 , 60-61 and 93-105 may be formed within and between the wellhead and the lower end of the first and at least one second conduits so as to surround and fluidly communicate with one or more well passageways of the well conduit system.
  • Various embodiments can comprise a subterranean separator with connecting substantially concentric or axially autonomous conduit walls and passageways for forming inlets (26), chimneys (27), downcomers (28), diverters (29), spreaders (30) and/or mist extractors (31), e.g., the embodiments illustrated in Figures 17 and 62-68 , to separate water, liquid and gas hydrocarbons, to perform fluid processing.
  • FIG. 1 may depict a heat exchanger (12), with substantially concentric or axially autonomous conduit walls, for exchanging heat between fluid within conduits and fluid within a subterranean fluid processing tank to perform fluid processing
  • Embodiments of the present invention can divide or commingle simultaneous fluid flow streams through autonomous or connecting well passageways, within first and at least one second conduits, at various depths to process or separate fluids for injection or production.
  • inventions may comprise selective control of simultaneous flow streams, e.g., Figures 17 , 38 , 45-48 , 60-132 and 135-140 , using one or more valves (24), or diverting apparatuses (25), placed within autonomous or connecting passageways.
  • Embodiments of the large diameter, high pressure well conduit system can be used to better contain fluids and pressures because the subterranean strata may aid internal pressure bearing capacity and thermally insulate downhole processing to provide better flow assurance.
  • Fluids may be produced to an above ground level to be cooled for the purposes of processing, then recompressed and placed with a subterranean separator or distillation large diameter pressure conduit to reheat and further process separated fluids prior to, e.g., transportation through a pipeline and disposal of unwanted fluids, e.g., contaminated water, within a subterranean injection horizon.
  • Inclusion of larger, thicker walled conduits with an increased effective wall thickness and pressure bearing integrity, using embodiments of the present invention, can provide greater resistance to corrosion and erosion to improve pressure and fluid well integrity.
  • Embodiments can include conduits and associated apparatuses, which can be engaged with connections using friction, welding, mandrels, dogs, receptacles, slots, slips, threads, bolts, clamps, hoop stress resistances and/or any other fasteners.
  • conduits and associated apparatuses which can be engaged with connections using friction, welding, mandrels, dogs, receptacles, slots, slips, threads, bolts, clamps, hoop stress resistances and/or any other fasteners.
  • the embodiments of Figures 50-54 , 60-61 , 93-105 , 119A-119E and 120-132 which illustrate various combinations of these connector types.
  • Embodiments of the present invention may use any suitable conventional connector.
  • inventions may use metal-to-metal, elastomeric and/or cement for the sealing of fluid communication passageways and/or engagement of conduits and associated apparatuses; e.g., the embodiments shown in Figures 5-7 , 14-15 , 18-28 , 30-31 , 33-37 and Fig. 50-54 .
  • Other embodiments may use single or double olive compression fittings (41, 42) to secure and seal two components of a wellhead assembly together and/or to secure and seal two conduits together.
  • Embodiments may provide for separate well bore penetrations for multiple wells through a single wellhead, e.g. the embodiments of Figures 15 , 17A , 17B and 50 to 54 .
  • a plurality of laterals may be drilled and completed from each of a plurality of wells through a single larger diameter high pressure main bore to, e.g., minimise the risk of leaks that may contaminate ground water formations and/or to minimise surface equipment in favour of, e.g., vegetation to minimize the carbon foot print and/or greenhouse gas emissions associated with constructing wells and/or infrastructure and producing multiple wells.
  • inventions may comprise directionally boring and placing protective linings in one or more wells to provide fluid communication between injectable and producible strata and at least one wellhead assembly (10), such as the embodiments shown in Figures 5-7 , 14-17 , 38-39 and 45-49 .
  • Embodiments can provide cased and cemented pressure integrity for lateral bores, typically referred to as level 6 multi-laterals, from a well of a large diameter, high-pressure conduit system main bore or from the junction of a plurality of wells at the lower end of said system, wherein desired hole sizes may be used with bore selectors in chamber junctions or with kick-over tools within drilling side-track pocket exit adaptations for drilling, lining and subsequent access to, e.g., perforate, hydraulically fracture strata and place proppants, and/or clean the bore after fracturing operations.
  • Larger diameter well conduit systems may provide more conduit placement options and the option for constructing more wells with batch operations to provide the opportunity to apply knowledge gained from one well to the next more easily, wherein the next well operation or lower end design may be changed to achieve the original objectives given knowledge gained from the previous batch operation, and wherein the scope of one well may be increased to account for the loss of scope on another to, e.g., retain a preferred well bore size and/or allow longer horizontal bores.
  • Large diameter, high pressure well conduit systems may allow, e.g., the use of the same drilling bottom hole assembly (BHA) on more than one well, rather than laying down the BHA to run casing then picking up a smaller diameter BHA to drill the next section, wherein the cost of rigging up on one well, rigging down, and then rigging up again on a subsequent well is also avoided.
  • BHA drilling bottom hole assembly
  • drilling mud drilling fluid
  • Large diameter, high pressure well conduit systems can be used to process and/or hold reserve drilling fluid, generally referred to as drilling mud, within the well that may be used on more than one well to similar depths, thus allowing fewer changes in mud density across a plurality of wells, and to provide a margin of safety with regard to severe mud losses to subterranean thief zones, since the loss in hydrostatic head is less for large diameter holes than small diameter holes at the same loss rates.
  • drilling fluid or mud may be stored within what is effectively a large cylindrical tank of the system which can include a riser for higher velocity fluid communication within the tank to remove boring debris with higher velocities within the riser, wherein other conduits within the tank may be used for cleaning the tank prior to completion of the well and/or as a separator and/or heat exchanger after completion of the well.
  • Embodiments may use gravity assisted fluid flow or cementation of large diameter high pressure conduit systems during or after boring of strata and placement of protective linings to provide better fluid flow or cement placement, which lowers the risks of losses to the weak subterranean formations that may prevent adequate cement placement.
  • Various embodiments can provide a plurality of wells vertically and/or laterally oriented and spaced to, e.g., provide improved recovery of subterranean deposits.
  • inventions can provide a conduit system for hydraulically fracturing strata for one or more wells individually or simultaneously to, e.g., provide improved recovery of subterranean deposits.
  • valves may selectively control fluid communication with computer operation (102, 108) of valves, e.g., using electrical, pneumatic and/or hydraulic operators and/or surveillance equipment that can be usable for observation of pressures, temperatures and/or flow-rates within one or more passageways.
  • Various large diameter, high pressure, well conduit systems may provide a plurality of lateral bores from each of a plurality of wells, which, through their proximity and hydraulic fracturing capabilities, may naturally provide an increased rate of recovery and/or provide subterranean thermally efficient processing spaces, which can be computer managed (102, 108) to optimize reservoir pressure maintenance and production.
  • Large diameter, high pressure conduit systems may use subterranean data gathering and control devices for operating subterranean processing of a plurality of wells through a main bore separator, thus providing an opportunity for continuous production and injection, which is usable for both reservoir pressure management and production, wherein unwanted subterranean fluids, e.g., produced water, may be injected back into the strata immediately after being produced to, e.g., help maintain reservoir pressures.
  • unwanted subterranean fluids e.g., produced water
  • Embodiments provide simple, low-cost improvements applicable to most subterranean well construction and production operations, which are far from obvious to the compartmentalized, distinct silos of drilling, completion and wellsite production processing practitioners, because the space provided by a larger diameter, higher pressure well conduit system can be used to place virtually any off-the-shelf apparatus within a subterranean contained environment.
  • Embodiments of the present invention can provide additional benefit through the use of conduits for cementing and circulation during construction, annulus monitoring during initial production, well bore cleaning for both construction and production processing operations, and, ultimately, switching from a large bore low friction production conduit to velocity string production conduits usable to lift produced fluids, e.g., water, which may retard production in later years through a larger bore.
  • FIG. 1 depict diagrammatic views of cross section slices through the environment and subterranean strata for a prior art above ground level (56) onshore drilling (51A) rig (51) above a line A1-A1, an onshore prior art coiled tubing drilling (51B) rig (51) above a line A2-A2, a wireline drilling (51D) rig (51) arrangement above line A3-A3, and a prior art offshore jack-up drilling (51C) rig (51) above a line A4-A4, respectively.
  • onshore drilling (51A) rig 51) above a line A1-A1
  • 51B onshore prior art coiled tubing drilling
  • 51D wireline drilling
  • 51C prior art offshore jack-up drilling
  • any rig including the rigs (51) depicted, can be used to operate and/or drill within a large diameter, high pressure conduit system (1); however, larger hoisting capacity rigs (51A and 51C) are, generally, preferred for installing said conduit system (1), particularly when such rigs are adapted for installing large diameter conduits.
  • Various rigs e.g., rigs that are specially designed for installation of large conductors by driving or boring, placing and/or cementing large diameter piles, can be usable for installing a large diameter, high pressure (LDHP) conduit system (1).
  • FIG. 1 Various embodiments of the present invention may be used in place of the general embodiment representations (1AX, 1AY, 1AZ and 1BA) shown in Figures 1, 2, 3 and 4 , respectively, wherein, e.g., an embodiment below line A1-A1 may drill one or more directional well bores for placement of conduits below a LDHP conduit system (1AX) using, e.g., adaptations of the whipstock and kick-over tool embodiments shown in Figures 113 to 132 , or the concentric conduits embodiment of Figure 5 .
  • Cable deployed apparatuses comprising, e.g., arrangements taught in GB2465478B , may be operated within a LDHP conduit system (1AZ) to, e.g., clean conduits (59) of a well bore, e.g. those of the separator depicted in Figures 17A , 60-61 and 93-98 , or to drill lateral bores through whip-stocks, such as those shown in Figures 113-132 .
  • boats 55 of Fig.
  • LDHP conduit system (1BA) which can be usable below, e.g., a subsea tree (53) located below sea level (54), and which is connected via a pipeline conduit to a platform (52) with various forms of one or more wells placed through a main bore within the strata (A4-A4), below mudline (57).
  • Figure 5 depicts a diagrammatic cross section elevation view through a high pressure, large bore conduit system (1) embodiment (1A) and subterranean strata, in which the conduit system (1) can be usable for communicating with a desired strata formation (61) through, e.g., perforated (60) conduit (59A) within conduits (2, 3, 4, 7 and 59).
  • a first conduit (2) embodiment (2A) generally termed as a conductor conduit, may be placed below ground (56) or mudline (57) level.
  • the conduit system (1) can include a plurality of conduit (3) embodiments (3A) that can include an associated plurality of inner radial loading surfaces (6).
  • the inner radial loading surfaces (6) can comprise any elastically flexible material and/or shape, or a partially plastically deformable material and/or shape, with an elastically flexible portion (6A), for extending from concentric (35) pipe body (4) embodiments (4A1-4A4) and across intermediate annuli (7) embodiments (7A) to contact associated loading surface (5) embodiments (5A), by radially extending from one pipe body to abut to an adjoining pipe body, so as to cause a sharing of hoop stress resistances so as to form a greater effective wall thickness (9).
  • the wellhead (10) may, e.g., be comprised of a smaller wellhead (10A1) within a larger (10A2) wellhead for hanging associated concentric (35) conventional conduits (59) and conventional annuli (58), and the pipe body embodiments (4, 4A1-4A4) that extend axially downward and substantially below the ground (56) or mudline (57), with associated annuli (7, 58), that can be accessible through said wellhead (10).
  • the well can be usable to produce or inject to a desired strata formation (61) through perforations (60), conduits (4, 59) and the wellheads (10).
  • tubing packers can be present, wherein any appropriate conventional completion apparatus may be included within a LDHP conduit system (1) because conventional apparatus is suitably sized for use therein.
  • the LDHP well conduit system (1A) can be, e.g., used to fluidly access significantly deeper formations (61), for ultra-high pressure and temperature applications, than is presently the convention or practice. This is due to a significantly greater number of conduit strings that can be used to sequentially isolate ever deeper subterranean formations.
  • an upper larger diameter wellhead (10A2) may have a significantly larger effective wall thickness (9) and associated higher pressure bearing capacity to support, e.g., conduits (59) and wellhead (10A1) arrangements, which are conventionally higher pressure due to their wall thickness and smaller diameters.
  • conduits without loading surfaces may comprise an inner most 7.3 cm (2 7/8"), 17 kg/m (11.44 pound per foot (ppf)), 655 N/mm2 (95 thousand psi (ksi)) yield strength tubing conduit (59A) that is capable of bearing a 1,698 bar (24,630-pounds-per-square-inch (psi)) collapse and a 1,754 bar (25,440-psi) burst pressure, within a 12.7 cm (5"), 34.3 kg/m (23.2-ppf), 1034.2 N/mm2 (150ksi) casing conduit (59B).
  • This casing conduit (59B) can bear a 1,788.4 bar (25,940-psi) collapse and a 1,730.2 bar (25,100-psi) burst, within a 17.8 cm (7"), 60 kg/m (41-ppf), 1,034.2 N/mm2 (150 ksi) casing conduit (59C), which is capable of bearing a 1,572.4 bar (22,800-psi) collapse and a 1,525.5 bar (22,120-psi) burst, within a 24.45 cm (9 5/8"), 105.7 kg/m (71.8-ppf), 1034.2 N/mm2 (150ksi) casing conduit (59D), which is capable of bearing a 1352.8 bar (19,625-psi) collapse and a 1,410.3 bar (20,450-psi) burst, within a concentric hoop stress sharing radial loading surface.
  • the concentric hoop stress sharing radial loading surface can be supported by a 29.85 cm (11 3 ⁇ 4") conduit (4A1), a 34 cm (13 3/8") conduit (4A2), a 40.6 cm (16") conduit (4A3), a 50.8 cm (20") conduit (4A4), and a 61 cm (24") conduit (4A5), wherein an effective wall thickness (9) can comprise the innermost 27.4 cm (10.772") internal diameter for the 29.8 cm (11 3/4"), 89.5 kg/m (60-ppf) conduit (4A1) to the outermost conduit 61 cm (24") outside diameter (OD) conduit (4A5), wherein a 55% efficiency of the nominal 16.8 cm (6.614") wall thickness, or 9.24 cm (3.6377") effective wall thickness for a 61 cm (24") OD conduit of 551.6 N/mm2 (80,000 psi) yield material, may be capable of bearing a 1,419 bar (20,575-psi) collapse and a 1,463 bar (21,219-ps
  • a large diameter high pressure conduit system (1) will, generally, elastically expand and compress the circumferences of larger diameter conduits, preferably those greater than 21.93 cm (8 5/8") OD and 18.73 (7 3/8") inside diameter (ID), to form a series of adjoined conduits that include radial extending loading surfaces, which can abut to an associated circumference of an inner or an outer pipe body to form an abutment hoop stress sharing reinforced conduit system that surrounds smaller diameter conduits, which are, generally, better able to bear pressures given the more rigid nature of their smaller diameter hoop stress bearing capabilities.
  • Loading surfaces of the present invention may have any shape that abuts two adjacent conduits, e.g., those shown in Figures 7 to 13 , 18-19 , 21-28 , 30-31 , 33-37 and 50-61 , so as to adjoin conduits after elastically expanding and compressing conduits during installation. Thereafter, when their pipe bodies attempt to elastically return to their original shape, the loading surfaces form abutments that allow stresses to pass through the abutment, as shown in Figures 11 to 13 .
  • a LDHP conduit system (1) can include housing one or more wells or associated conduits, and can include fluid communication conduits and/or well processing conduits with, e.g., computer controlled (108) compressors and/or pumps as described in Figure 17 .
  • Figure 6 shows an elevation diagrammatic view of a slice through a subsea casing boring placement embodiment and subterranean strata during, e.g., a floating drill ship or semisubmersible rig drilling.
  • Figure 6 shows placement of an embodiment (2B) of the outermost first conduit (2) of a large diameter high pressure conduit system (1) embodiment (1B), which includes drilling a strata bore (66) below a mudline (57) with a bottom hole assembly BHA (65).
  • the BHA (65) comprises a boring bit (71) and hole openers (72), integrated with drill pipe (73) between upper (62) and lower (63) slurry passageway tools, as described in GB2475626A , for placing a first conduit (2) with a loading surface (5) embodiment (5B), consisting of the inside circumference of the pipe body (4), which is shown engaged to a subsea (54) guide base (64) that comprises part of the first conduit head subassembly (17) embodiment (17B).
  • the first conduit (2) can be carried and placed with the BHA (65) and drill string (73), within the strata bore (66), by boring with the bit (71) and hole openers (72), wherein fluid can be circulated downward (67) and returned upward (68, 69) to remove drill cuttings or strata debris from the bore (66).
  • an actuation tool e.g. a drill pipe dart
  • a drill pipe dart may be pumped through the drill string (73) to open a lateral conduit (194) cementing (194B) port (70) to perform a gravity cementing top-up cement job, and the BHA (65), drill string (73), upper (62) and lower (63) slurry passageway tools may be removed.
  • the first conduit (2) of the present invention may be installed by any means, e.g., rotary or casing drilling of the conduit (2) with any type of rig, hammering, or a driving of the conduit (2) into the mudline (57) or ground level (56) with any type of large hammer, or the vacuum sucking of the conduit (2) into the mudline with any type suction pile apparatus and method.
  • any means e.g., rotary or casing drilling of the conduit (2) with any type of rig, hammering, or a driving of the conduit (2) into the mudline (57) or ground level (56) with any type of large hammer, or the vacuum sucking of the conduit (2) into the mudline with any type suction pile apparatus and method.
  • Figure 7 illustrates a diagrammatic elevation slice through the subterranean strata and a LDHP conduit system (1) at subsea (54).
  • the Figure further includes a mudline (57) or ground level (56) installation of a second conduit (3) embodiment (3C) within a first conduit (2) embodiment (2C), with cementing of the arrangement within the strata.
  • a wellhead (10) first assembly embodiment (10C), with a first conduit head subassembly (17) embodiment (17C) and at least one second conduit head subassembly (18) embodiment (18C), and including associated lower end first and second conduits (2, 3), can be usable to form a large diameter high pressure conduit (1) embodiment (1C).
  • Figure 8 shows a diagrammatic plan view of the loading surface (6) embodiments (6C), with circulation and lateral conduit (194) cementing (194C) tool flow paths (70).
  • the second conduit (3) having spherical loading surfaces (6C) extending through the intermediate annulus (7C), can be inserted within the first conduit (2) to abut against the circumferential loading surface (5C) of the pipe body ID and adjoin the two conduits (2, 3) pipe bodies (4) to share hoop stress resistance through their abutment.
  • a strata bore (66) was formed with a separate drill string, and the second conduit (3) was subsequently placed within the first conduit (2), with a slurry passageway tool (74) at its upper end and drillable casing shoe (76) at its lower end, using a valve arrangement of the present invention that comprises upward circulation (68), which can occur downward to circulate the conduit (3) into the bore (66) if the actuation tool (78) is not present and the spring (79) of the passageway tool uses the plate (80) to cover its vertical passageway (82).
  • the elastic compression of the larger effective diameter loading surfaces (6) of the inner conduit (3), within the elastically expanded smaller diameter loading surface (5) of the outer conduit (2), may occur with hoop forces between the pipe bodies that can be formed by the axially downward force of the string (3, 73, 74, 75, 76), which can be filled with a fluid heavier than the surrounding fluid to increase the weight for expanding the first conduit (2) and compressing the second conduit (3) to adjoin the conduits (2, 3) and abut the loading surfaces (5, 6), by allowing the spherical profile of the shaped loading surface (6C) to wedge into the circumferential loading surface (5C) until the wellhead (10C) lands on the upper end of the first conduit (2).
  • Portions of the spherical abutment-loading surface (6C) may plastically deform during the loading, provided that the elastic hoop stresses of the conduit (3) pipe body (4) embodiment (4C) are retained for sharing through the remaining elastic portion of the abutment.
  • Figure 13 describes such an embodiment.
  • Cementing of the second conduit (3) within the first (2) may be accomplished with an actuating tool (78) pumped through the drill string (73) and engaged with the spring (79) loaded plate (80) to divert cement through the lateral passageway (70), to flow axially downward (81) within the annulus (7C) between the conduits (2, 3) and around the loading surfaces (5C, 6C), with pump force and gravity past, e.g., any fluid thief zone (77).
  • the spring (79) can be compressed by the use of a shoulder or extension (75) for forming the loaded plate (80) for diverting the cement through the lateral passageways (70). Displaced fluid can return through the slurry passageway tool vertical passageways (82).
  • Such gravity cementing is preferable to top-up conventional cement jobs because circulation may still bypass shallow weak formations with potential fluid theft zones (77), whereas normal conventional cement placement occurs through the centre of the string with displaced fluids and cement returned through the weaker annulus; however, any form of cementing, appropriate to the downhole conditions, may be used with the present invention.
  • Figures 9, 10 and 11 show a plan view with section line B-B and detail line C above an elevation cross section view along line B-B with detail line D, a magnified detail view within line C, and a magnified detail view within line D, respectively, of a large diameter high pressure conduit system (1) embodiment (1D).
  • a second (3) inner conduit is shown concentrically placed within a first (2) outer conduit, wherein the second (3) inner conduit and first (2) outer conduit have continuous elastically compressible and expandable pipe bodies (4), respectfully, with circumference loading surface (5) embodiments (5D) and an intermediate spherical loading surface (6D) extending radially through the annulus (7) between the conduits to engage a plurality of the spherical radially disposed loading surfaces (6D) to the associated loading surface circumferences (5D).
  • the abutment of one conduit to the other may comprise expanding the effective diameter of the radial loading surfaces (6D) of lesser diameter around the associated outer loading surface circumferences (5D, 5D2) prior to adjoining the conduits (2D, 3D) by weighted wedging, hydraulic piston driving, hammering, rotating, and/or any other means of forming a hoop force sufficient to place one conduit within the other conduit loading surface (5D1) by elastically expanding the outer pipe body (4) conduit (2D) and/or by compressing the intermediate loading surface (6D) and/or inner conduit (3D) to, in use, install one conduit within the other and share hoop stress resistances (8, 8D).
  • This adjoining of the conduits forms a greater effective wall thickness (9), which can be usable to bear higher pressures than said conduits (2, 3) could independently bear without sharing hoop stresses.
  • the radial extending surfaces are illustrated as ball bearings held by an intermediate concentric centralizing structure (83D), which is shown engaged around the outside diameter of the at least one second conduit (3) before it is disposed within the first conduit (2), or another different surrounding second conduit.
  • Figures 12 and 12A show sliced plan view and diagrammatic plan cross section view, of the loading surface portion, of a large diameter high pressure conduit system (1) embodiments (1E1) and (1E2), respectively.
  • the Figures illustrate an example of an additional second conduit (3E2) installed within a second conduit (3E1), which has already been installed within a first conduit (2E), or alternatively second conduits (3E1 and 3E2) with an intermediate centralizing structure (83E1 or 83E2) installed together as a unit within a first conduit (2E) having loading surface (6E3).
  • the intermediate concentric centralizing structure or strapping (83E1) may comprise machine pressed circumferential concentric conduit plates (85) deformed over corresponding orifices and loading surfaces (6E1), prior to riveting (84) the conduit plates together, as shown in the arrangement of Figure 12 .
  • a centralizing structure (83E2) comprising a metal and/or inflatable/swellable material (84 and 85, respectively, or vice versa) arrangement, with optional orifices (86), can be used, as shown in Figure 12A .
  • the intermediate concentric centralizing structure can be placed between a second (3E1) conduit and at least another second (3E2) conduit to abut the circumferential loading surface (5) embodiments (5E1, 5E2) of the pipe bodies (4E1, 4E2) against the intermediate spherical (6E1) or inflated/expanded metal (6E2) loading surfaces (6) to, in use, share hoop stresses (8, 8E, 8E1 or 8E2) after placement through a greater effective wall thickness (9).
  • the illustrated centralizing structure (83E1) may be replaced with an inflated/expanded metal arrangement (83E2), or any other variation of loading surface arrangement, to engage circumference loading surfaces (5, 5E1, 5E2) before or during installation, e.g., loading surface (6E1) may be a combination of ball bearings, tubing and/or cable axially aligned or helically coiled around the installed conduit (3E2) and held by a series of centralizing structures or strappings (83E) to affix the loading surface during expansion and contraction of the pipe bodies (4, 4E1, 4E2) using, e.g., weight, hammering or a hydraulic piston installation within the larger second conduit (3E1) or the first conduit (2E), through a loading surface (6E3) if, e.g., the second conduits (3E1, 3E2) are installed together as a unit.
  • loading surface (6E) may be a combination of ball bearings, tubing and/or cable axially aligned or helically coiled around the
  • the two second conduits (3E1, 3E2) may be installed as a unit with an intermediate loading surface arrangement, such as that shown in (83E1) of Figure 12 or that shown in (83E2) of Figure 12A .
  • Orifice arrangements (86) can be filled with, or can contain encapsulated fluid, to initiate an expansion of, e.g., swellable elastomeric material, or the orifices (86) can be left open to provide space for a metal to compress.
  • the metal (85) may be arranged with the elastomer (84) bearing, or vice versa, such that at least a portion of the hoop stresses (8E2) may be shared.
  • the shape of the loading surfaces (6) may be any shape to provide the desired level of effective wall thickness (9) efficiency, wherein said efficiency may be less than 100% to provide the ability to progressively increase the overall pressure bearing capability by successively adjoin conduit body (4) walls and loading surfaces (5, 6), for sharing a portion of the effective wall thickness (9).
  • a centralizing structure e.g. (83D of Figures 9-11 , 83E1 and 83E2 of Figures 12 and 12A , 83F of Figure 13 and 83J of Figure 19 ) may be covered with, e.g., a elastomeric substance and/or reactive swellable substance that both seals the annulus (7) between conduits (2, 3) and supports the loading surfaces (6).
  • the annulus between conduits (2, 3) and loading surfaces (5, 6) may be, e.g., cemented after installation when, e.g., plastic deformation is used (87 of Figure 13 ).
  • Figure 13 depicts a sliced plan cross section view of a portion of a large diameter high pressure (LDHP) conduit system (1) embodiment (IF), which illustrates the sharing of hoop stresses (8) through an effective wall thickness (9) larger than would be possible without such hoop stress sharing through the abutment of a loading surface (6F), which can be welded (88) to the second conduit (3) that is abutted against a circumferential loading surface (5) to adjoin the pipe bodies (4) of the first (2) and at least one second (3) conduits.
  • a loading surface (6F)
  • a limited amount of plastic deformation (87) of a loading surface (5, 6F) may be desirable to better share the hoop stresses, improve the effective wall thickness efficiency, and provide for the abutment and adjoining of one large diameter conduit to another, so to increase the overall pressure bearing capacity.
  • the large diameter provides space within the system (1) for placement of axially concentric and/or autonomous conduits to one or more wells through the improved single main bore of the LDHP conduit system (1), wherein any material may fill the annular space (7) between the conduits (2, 3) to facilitate placement, abutment, adjoining, sealing and/or pressure bearing capacity, e.g., plastically deformable and/or a water or oil swellable material activated after placement of the second (3) within the first (2) conduit.
  • the Figure shows an elevation view diagrammatic slice through subterranean strata and a large bore high pressure conduit system (1) embodiment (1G), which comprises a chamber junction (21) embodiment (21G), single olive (41) embodiment (41G) and double (42) olive embodiment (42G) arrangement.
  • the Figure depicts the operation of boring with a drill string (73) lower end bit (71) and a hole-opener (72), which is centralized (92) within a casing (89) or well lining (59G) and guided through a chamber junction (21G), to function as an axially autonomous conduit (34) that extends axially downward through a second conduit (3G3) and bore selector (32, 32G).
  • the conduit (34) is suspended, with the use of an olive (41G), within a wellhead spool (14G) to provide a drilling fluid communication conduit, through a tank (13) embodiment (13G), for holding and circulating drilling fluid, similar to a trip tank, formed by the chamber junction (21G) LDHP conduit system (1G).
  • Boring may proceed more conventionally through the casing (89) until the well lining (59G) can be hung from the lower end of the chamber junction.
  • minor skidding of the rig over the exit bores (34) of the chamber junction (21G) may occur during boring, through separately placed axially autonomous conduits hung from a wellhead top (e.g. 10T of Figure 54 ) and fixed to the spool lower wellhead (10G).
  • drilling or boring of a strata bore (66) may comprise keeping drilling fluid within the tank (13G), which is isolated at its lower end by drillable cement (91) in the adjacent autonomous conduit (34).
  • casing (89) or well lining (59H) is released from the single olive (41G) and the casing (89) is placed and cemented, it will seal the tank (13G) for drilling the cement (91) and adjacent strata bore.
  • casing (89) which may form autonomous conduit (34) bores within the LDHP conduit system chamber junction (21), may be accessed from a central position to save the installation time of moving or skidding a rig by rotating the bore selector (32G) to communicate with various wells conduits (34).
  • the tank (13G) may be used for improved well control of the primary fluid barrier by holding a volume of fluid, which falls more slowly than is the convention because leak rate consumes drilling fluid from a larger volume to provide a longer period before closing the second barrier blowout preventers (90), if required.
  • Circulation (93) can occur downward through a lateral conduit (194) port (194G), in the wellhead spool (14G), between the casing (89) and strata bore (66), wherein the fluid volume returned (68) is the normal pumped volume (67) plus circulation (93) less any fluid losses, wherein the probability of fluid loses and the casing becoming stuck may be reduced through better maintenance of the hydrostatic head with the tank (13G) functioning like a rig trip tank.
  • FIG. 14 and 14A the elevation view of the LDHP conduit system (1G) and an isometric view of a conventional compression pipe fitting arrangement with a single olive (41) arrangement.
  • the tank's (13G) high pressure bearing capacity is formed by the abutment of loading surfaces (6, 6G) to adjacent conduits (3G2, 3G1, 2), and the clamp (15G1) and flanged (15G2, 15G3) securing (15) of a large diameter high pressure wellhead (10G), wherein the wellhead may comprise a larger diameter wellhead (10G1) with first (17, 17G) and a plurality of second (18, 18G) conduit head subassemblies engaged to conduits (2, 3G1-3G3) which are intermediately sealed (16) with a single olive (41G), double olives (42G), and gaskets (16G1, 16G2, 16G3), usable for both securing and sealing the upper end conduits of the tank engaged to an upper end larger (10G1) and smaller (10G2) wellheads.
  • Prior art use of a single olive (41) to secure and seal permanent conduits within a wellhead is equivalent to the common plumbing compression pipe fitting, wherein the olive (41) is placed over the conduit (94) and compressed between a spool (96) and moving engagement (95), generally a screwed nut is used to secure and effect a seal.
  • the present invention makes a significant improvement over prior art with the use of a single olive (41G) to temporarily suspend casing (89) within a strata bore (66) during boring, such that the casing may be lowered after boring in stages during boring to provide, e.g., better circulation through weaker formations when using larger bits (71) and hole openers (72) to better facilitate improved placement of subterranean passageways through the LDHP conduit system (1).
  • the present invention may also provide significant improvements with a double (42) olive (41) casing hanger, wellhead securing and sealing arrangement as further described in later Figures.
  • Figure 15 depicts an elevation view diagrammatic slice through a large diameter high pressure conduit system (1) embodiment (1H) with a chamber junction (21) embodiment (21G) and double (42) olive (41) embodiment (42H).
  • the Figure illustrates how a chamber junction may be drilled without a bore selector and with minor skidding of the rig over the exit bores (34) of the chamber junction (21G), through separate axially autonomous conduits between the chamber junction and the wellhead top (e.g. 10T of Figure 54 ), which is secured at the upper end of the double olive (42H), and which secures and seals the conduits (2, 3) adjoined with radial loading surface (6) abutments to the circumferences of the pipe bodies.
  • Figure 15 shows casings (89) with casing annuli (58H), wherein the casings (89) may be suspended from casing hangers of a wellhead that can be engaged to the top of the double (42) olive (41) arrangement and potentially to the exit bore (34) conduits, as shown on the right hand side, or the casing may be carried (89) with the drill string in a managed pressure conduit drilling arrangement of the present inventor, as shown on the left hand side of Figure 15 .
  • Figure 16 shows a diagrammatic elevation view of a cross section through a prior art vertical separator (11), wherein the present invention can include the use of such a separator.
  • the Figures show the separator disposed downhole, with an inlet (26) engaging a diverter (29) to roughly separate entrained gases and liquids, which may fall with gravity through a downcomer (28) to engage a spreader (30).
  • the separation process allows gas to be separated and to migrate through a hydrostatic liquid level (103), through a chimney (27) and mist extractor (31), to a gaseous fluid flow (97).
  • the liquid e.g. hydrocarbons, of a lighter density, may separate with gravity to a level (103) for extracting a substantially hydrocarbon liquid fluid flow (98), such that heavier density water below a water level (104) can migrate to the lower level water fluid outlet (99).
  • a pressure-actuated valve (105) regulates the liquid fluid level (103), while the coordinated operation (102) of the hydrocarbon liquid level valve (100) and water level valve (101) regulates the interface (104) between liquids.
  • Figure 17 is a diagrammatic flow chart of a large diameter high pressure well conduit system embodiment (IX), depicting a LDHP conduit system (1) that can comprise first (2X) and at least one second (3X) conduit bodies (4) adjoined with loading surface (5, 6) abutments to share hoop stresses (8) for forming a greater effective wall thickness (9) with an efficiency greater than the conduits (2, 3) would possess in isolation, without said sharing of hoop stresses.
  • the Figures includes a wellhead (10) embodiment (10X) that can be secured and sealed to the upper end from one or more wells and associated conduits (34X, 89X, 59X), usable for injecting fluids to the strata and/or producing fluids from the strata for transportation (106).
  • Transported fluids may be pumped and/or compressed (107) for said transportation (106) and/or processed (109), which may be computer controlled (108), and wherein the pumping, compression, fluid processing and computer control may be conventionally and/or environmentally powered (110).
  • the larger diameter and higher pressure bearing capability of the present invention provides significant improvements for increasing the efficiency of downhole processing (109) comprising, e.g., subterranean tanks (13), separators (11) and heat exchangers (12) for production, injection and processing optimization of fluid communication to and from one or more passageways through the strata, and from one or more wells within the main bore of the LDHP conduit system (1).
  • These improvements can include providing accessibility and control via, e.g., valves and sensors engaged with a computer monitoring and control system using downhole cables and/or hydraulic lines.
  • Figure 17B shows a diagrammatic plan view of the wellhead (10) embodiment (10I) and bores of an embodiment (1I) of a LDHP conduit system (1) associated with Figure 17A .
  • the Figure illustrates the arrangement of wellhead (10I) interfaces that may comprise, e.g., main well bores (3411, 3412) with an upper end dual bore valve tree, wherein the conduit system comprises a single main conduit tank forming a separator (11I of Fig. 17A ) and/or heat exchanger, with supporting conduits (34I3, 34I4) usable for operating the separator (11I of Fig. 17A ).
  • 17A and 100, 101 of Figure 16 may be passed through (116) the wellhead. Additionally, downhole pressure, temperature and/or fluid level sensors, and/or sensor cables may pass through (117) the wellhead, while downhole flow meters and/or meter cables can pass through (118) the wellhead. Any suitable devices, e.g. chemical injection lines, may pass through (119) the wellhead.
  • FIG. 17A a diagrammatic elevation cross section through a large diameter high pressure (LDHP) conduit system (1) embodiment (1I), is shown, with cut-out and break lines representing removed portions.
  • the Figure illustrates a high pressure separator (11) embodiment (11I) below a wellhead (10) embodiment (10I), which can be suitable for processing fluids from, e.g., a substantially gas shale gas deposit.
  • the Figure shows that gas flows (113) into the separator inlet (26) from a horizontal section (111) of the axially autonomous (34) well bores (34I1, 34I2), which are shown with a break lines representing the removal of a lower portion of the wells, wherein the well 34I1 exits from a whipstock (46I) arrangement (e.g.
  • a whipstock (46I) arrangement e.g.
  • Production may be controlled with the subsurface safety valve (241) shown within the left cut-out, wherein production (113) travels, e.g., through the well bore (34I1) until it encounters the diverter (29), which may comprise, e.g., a cable deployable plug (25A of Figure 119A ), whereby production can be diverted to the separator (11I) inlets (26). Fluids are communicated upward in the chimney (37) to re-enter the well conduits (34I1, 34I2), through a cable placeable mist extractor (31), which further knocks out liquids to the downcomer (28A) before the gaseous production is extracted (97).
  • the diverter which may comprise, e.g., a cable deployable plug (25A of Figure 119A ), whereby production can be diverted to the separator (11I) inlets (26). Fluids are communicated upward in the chimney (37) to re-enter the well conduits (34I1, 34I2), through a cable place
  • the cable deployable diverter (29) and mist extractor (31) may be removed to access the lower end of the wells (34I1, 34I2). Gravity separation of the liquid can occur as it exits the inlet (26) and downcomer (28A) to form a liquid level (103) above primary (28B, 30A) and secondary (28C, 30B) downcomers and spreaders, respectively. If the separator (11I) stops at the lower end of the conduits (2, 3), as shown, the downcomer (28C) and spreader (30B) are omitted.
  • the hydrocarbon (98A) and water (28D) outlets or intakes may be disposed at differing depths using separate conduits or combined at a single depth in a conduit (34I3) to affect the fluid levels (103, 104).
  • Separated water may be taken from conduits (34I3) using pump suction, which is discharged to (34I4) annulus through an orifice (114) for disposal within the strata until the water level (104) drops and a sensor detects hydrocarbons, wherein the pump is switched from water disposal to production until gas reaches an outlet (98A, 28D) and suction is lost. Thereafter, the pump is stopped and the separation process continues until a different sensor, within the separator, determines the pump should be restarted.
  • separating, e.g., natural gas liquids (NGLs) pressure within the separator (11I) may be used to communicate NGLs between the gas liquid level (103) and the water level (104) through an outlet (98A) at the upper end of an axially autonomous (34) conduit (34I3), while water is forced axially down the lower end of conduit (34I3) through a downcomer (28D), when a plug ( e.g. 25A of Figure 119A ) is placed, via cable operations, in a nipple between the hydrocarbon liquid separator outlet (98A) and water disposal inlet (28D).
  • NGLs natural gas liquids
  • Water entering the conduit (34I3) from an outlet (28D) may be disposed of using injection into the strata through the conduit (34I3) orifice (114) and annulus below the lower liner hanger (106) of a well (34I2), or the conduit (34I3) may be placed within its own strata bore to a desired location for water disposal or, e.g., a water flood for reservoir pressure maintenance.
  • conduits (2I, 3I) of the LDHP conduit system (1I) separator (11I) may extend axially downward from the wellhead (101), vertically, or the conduits (2,3) may extend axially downward and laterally along line (112), at inclinations and dog-leg severities generally limited by the stiffness of placing and abutting large diameter conduits, albeit said loading surfaces may be adjusted to accommodate flexure at predetermined depths while retaining a proportion of the efficiency for a more rigid arrangement. If the separator (11I) and conduit system (1I) conduit (2, 3) extend along well inclination (112), the downcomer (28C) and spreader (30B) allow a deeper hydrocarbon and water interfaces that may use hydrostatic pressures for separator operation.
  • the supporting axially autonomous (34) conduits (34I3, 34I4) may be configured in a various ways to interface with well bore conduits (34I1, 3412) and/or producible and/or injectable fluids.
  • the build-up of solids within the separator (11I) may be removed by placing fluid communicating straddles, e.g., the straddle (25E) of Figure 119E may be placed in the nipple (107) across communication ports (28A-28E, 98A-98B) to seal them, while allowing fluid through the centre of the straddle to fluidly circulate between the lower ends (115) of the supporting conduits (34I3, 34I4) to clean solids from the system.
  • Cable operable fluid motorized tools of the present inventor may use, e.g., brushes, bits and other tools deployed from the rig (51D of Figure 3 ) for maintenance and cleaning.
  • the lower orifice (114) can be used for cementing axially down the annulus below the lower liner hanger (106), after which a rotary cable tool may be used to clean any residual cement within the conduits.
  • ball, dart or other drop mechanism may operate sliding side doors, spring returns and/or otherwise actuated lateral ports or valves may be operated by dropping a ball down one conduit (e.g. 34I3) and taking fluid returns through the other (e.g.
  • any subterranean device e.g., transponders, receivers, acoustic devices, sensors, fibre optic cables, control lines, flow meters, valves (24), sliding side doors, circulating valves, diverting apparatuses (25), nipples (107), plugs, cementing plugs, wiper plugs, dropped actuation devices, such as balls/darts/cylinders, remote controlled devices, pressure/temperature activated devices, valves, chokes, orifices, jet/velocity pumps, chemical injection apparatuses, sensors, straddles, bomb hangers and gauges), or any other suitable device may be operated within the separator through wellhead (10I) interfaces.
  • any subterranean device e.g., transponders, receivers, acoustic devices, sensors, fibre optic cables, control lines, flow meters, valves (24), sliding side doors, circulating valves, diverting apparatuses (25), nipples (107), plugs, cementing plugs, wiper plugs,
  • Figure 18 depicts a plan view with line E-E above a cross section elevation view along line E-E, with detail lines F and G associated with Figures 19 and 20 , respectively, with dashed lines showing hidden surfaces, showing a LDHP conduit system (1) embodiment (1J) and double (42) olive (41) embodiment (42J).
  • a second conduit (3) embodiment (3J) is abutted and adjoined to the first conduit (2) embodiment (2J), with a loading surface (6) axial helical embodiment (6J) abutted to an associated loading surface (5) embodiment (5J), with an upper end wellhead (10) embodiment (10J).
  • the wellhead is shown comprising the upper ends of the adjoined conduits secured and sealed with a double olive arrangement.
  • the axial helical nature of the loading surfaces may be used to facilitate a turning or screwing abutment during placement during hoop force insertion comprising, e.g., hammering, weight and/or hydraulic means. While conventional well designs engage a thick metal wellhead to the upper end of well conduits, the depicted wellhead (10J) builds the strength of the wellhead with successive layers of second conduits (3) within a first conduit (2), wherein the intermediate double olive arrangement is also a loading surface arrangement.
  • Figures illustrate magnified detail views within lines F and G of Figure 18 , with dashed lines showing hidden surfaces, illustrating the axial helical disposed loading surface (6J) on the body (4) of the second conduit (3J), that can radially extend across the annulus (7) between conduits (2, 3) and can be abutted to the circumferential loading surface (5) of the first conduit (2J) to form a larger effective wall thickness (9J2).
  • An upper end wellhead (10J) is formed by first (17) and second (18) conduit head subassembly embodiments (17J, 18J), wherein a double (42) olive (41) embodiment (42J) comprising two single olives (41J1, 41J2) can secure and seal the pipe bodies and wellhead flanges (120, 121), using a wedge (122) embodiment (122J).
  • the arrangement forms a greater wellhead effective wall thickness (9J1, 9J2) than wellhead conduits that have not been adjoined and abutted with loading surfaces to share hoop stresses.
  • the shape and slenderness of the loading surfaces (6J) allows, e.g., elastic movement of the helical extension (6J) plastic deformation or bending of its end, wherein the annulus (7) may be filled with, e.g., cement or fluid reactive swellable elastomers which swell after placement, to secure the radial loading surfaces from further deformation or bending.
  • Partially securing the abutment of the loading surfaces (5, 6) with a relatively flexible material provides a percentage of the effective wall thickness (9J2) and easier installation of successive second conduits (3) within a LDHP conduit system (1), which becomes more difficult to expand with each adjoined second conduit (3).
  • Figures 21 and 24 are plan views with section lines H-H and J-J above associated elevation cross section views along H-H and J-J, having detail lines I and K associated with Figures 22 and 25 , respectively.
  • the Figures illustrate double (42) olive (41) embodiments (42J) comprising both securing (15) and sealing (16) embodiments (15J) and (16J), wherein the sealing, securing arrangement is in a pre-engagement of the securing (15J1) seal (16J1) position and post-engagement of the securing (15J2) seal (16J2) position.
  • Figures 22 and 25 depict magnified detail views within lines I and K of Figures 21 and 24 , respectively, showing the double (42) olive (41) wedge (122) embodiment (122J) in an pre-installed position (122J1) and post-installed position (122J2).
  • the upper portion of the wedge (122JU) can be urged from the installation, securing and sealing positions (122J1, 15J1, 16J1) into the installed, secured and sealed positions (122J2, 15J2, 16J2), respectively, by radially urging the inner single olive (41J2) inward from the pre-installation, unsecured and unsealed position (41J2A) to the installed, secured and sealed (41J2B) positions, wherein the inner surfaces of the olives (41J1, 41J2) are also secured and sealed against the surfaces of the wedge (123).
  • Figure 22 also shows an outer single olive (41J1, 41J1A) with the inner single olive (41J2) for forming the olive arrangement (42J), while Fig. 25 also includes an outer single olive (41J1, 41J1B) with the inner single olive (41J2) for forming the olive arrangement (42J).
  • Figures 23 and 26 are magnified elevation views within detail line G of Figure 18 which show the double (42) olive (41) embodiment (42J) within the wellhead (10J) in a pre-engagement, unsecured (15J1) and unsealed (16J1) position and a post-engagement, secured (15J2) and sealed (16J2) position, respectively, to form the LDHP conduit system (1) embodiment (1J) shown in Figure 18 .
  • the wellhead flange (121) support (10JS) engages the double olive arrangement (42J) between the inner (121) support (41JS) and outer (120) support (41JS) of the wellhead (10, 10J) flanges of the associated first (17J) and at least one second (18J) conduit head subassemblies.
  • the wedge (122J), having larger inner and outer diameters is urged axially downward to urge the upper wedge portion (122JU) towards the lower wedge portion (122JL, lower wedge portion (122JL) also shown in Figs. 22 and 25 ) to urge out the loading surfaces of the inner (41J2) and outer (41J1) olives (41) for expanding the outer conduit and compressing the inner conduit to abut the loading surface circumferences (5) of the wellhead flanges (120, 121); and thus, wedge loading surfaces (123) with a hoop force to adjoin the second conduit (3J) to the first conduit (2J) and form the wellhead (10J).
  • the dashed lines of Figure 26 represent an alternative wellhead (10) embodiment (10J1) and double (42) olive (41) embodiment (42J1), wherein the wedge may be urged axially upward or downward to provide a hoop force with, e.g., a receptacle (124, as also shown in Figs.
  • Figures 27 and 30 are plan views with section lines L-L and N-N above associated elevation cross section views along L-L and N-N, having detail lines M and O associated with Figures 28 and 31 , wherein Figures 28 and 31 are magnified detail views within lines M and O, respectively, depicting a double (42) olive (41) embodiment (42L).
  • the double (42) olive (41) embodiment (42L), depicted in Figures 28 and 31 includes securing (15), sealing (16) embodiments (15L) and (16L), as shown in Figures 27 and 30 , which can use inner (41L2) and outer (41L1) olive (41) loading surfaces, usable, e.g., between the wellhead (10J) circumferential loading surfaces (5) of Figures 18 to 20 and the wellhead (10K) of Figure 33 or (10L) of Figures 34 to 37 , wherein the second conduit (3L, shown in Fig. 34 ) loading surfaces (6) are below the wellhead.
  • the Figures 27, 28, 30 and 31 include a sealing, securing arrangement that is illustrated in a pre-engagement wedge (122L, 122L1) unsecured (15L1) and unsealed (16L1) position and a post-engagement wedge (122L, 122L2) secured (15L2) and sealed (16L2) position.
  • the inner (41L2) and outer (41L1) olives (42) shown in unsecured and unsealed positions (41L2A, 41L1A, respectively) are urged into secured and sealed positions (41L2B, 41L1B, respectively) to engage their radial extending circumferential loading surfaces to the circumferential loading surfaces of the wellhead and wedge sealing profiles (123), wherein the upper wedge portion (122LU) may be held while the lower wedge portion (122LL) is urged between the olives (41) of the double (42) olive (41) arrangement.
  • Figure 28 shows an alternative J-slot (124LJ) arrangement in dashed lines for instances where a flush wedge arrangement is desired, and a J-slot mandrel is place within the J-slot to hold the upper portion (122LU) while urging the lower one (122LL), or vice versa, during removal of the double olive arrangement (42L).
  • FIG. 29 and 32 the Figures illustrate isometric views of an installation tool tong (126) embodiment (126A) usable for installing the securing (15) and sealing (16) loading surface embodiments (15L, 16L) of Figures 27 to 28 and Figures 30 to 31 , wherein the tongs may be operated by any means, e.g. hydraulic cylinders, mechanical or electrical driven gears or screw drives and/or pneumatic pistons, such that the tongs are inserted into the wedge receptacles (124L, shown in Figures 28 and 31 ) and moved between positions (126A) and (126B), wherein either the lower (124L) or upper (124L) wedge portion is moved to form a hoop force for installation or removal.
  • any means e.g. hydraulic cylinders, mechanical or electrical driven gears or screw drives and/or pneumatic pistons, such that the tongs are inserted into the wedge receptacles (124L, shown in Figures 28 and 31 ) and moved between positions (126A) and (126B
  • Figure 33 illustrates a magnified elevation view within detail line G of Figure 18 , showing a wellhead (10) embodiment (10K) with a double (42) olive (41) embodiment (42K), and also comprising pre-engagement wedged (122), securing (15) and sealing (16) embodiments (122K, 15K, 16K, respectively) that are usable to form a LDHP conduit system (1) embodiment (1K).
  • Seals (127) at the lower end of the wedge embodiment (122K) may be urged axially downward between the wellhead (10K) flanges (120, 121) of first (17) and at least one second (18) conduit head embodiment (17K, 18K), while hydraulic pressure is applied above the seals (127), wedge (122K) and support surface (10KS) to expand the circumference loading surface (5) of the outer flange (120) and to compress the circumferential (5) loading surface of the inner flange (121).
  • Installation hoop forces for engaging the inner (41K2) and outer (41K1) olives (41), used to share the hoop stresses of the flanges (120, 121) of the double olive arrangement (42K), may be reduced by securing and sealing the olives before release of any hydraulic pressure trapped by seals (127).
  • the interface to the hydraulic lateral opening (194) embodiment (194K), for hydraulically driving installation hoop forces, may be similar to (194L) of Figures 34 to 37 , wherein hydraulically driven fluid is used in the annulus (7) between the at least one second conduit (3) and the first conduit (2) to compress and expand the conduits and to drive a lower end piston with fluid communicated into the annulus (7).
  • the profile (10KS) supports the seals (127) to allow application of pressure between the loading surfaces (6K) and the conduits (2K, 3K) so as to install the pipe bodies with associated expansion and compression to allow abutting of the loading surfaces (6K) to the circumferential (5) loading surface of the first conduit (2K) once the wedge (122K) is installed.
  • the pressure may be relieved to provide abutment with a plug or cap (128) for sealing the hydraulic fluid communication lateral opening (194K) from contaminates.
  • the wedge (122K) includes an embodiment of a J-slot (125K).
  • Figure 34 depicts an isometric view with a quarter section of the outer first conduit assembly (2L) removed, with detail lines Q, R and P, and Figures 35, 36 and 37 depict magnified detail views within the lines of Q, R and P of Figure 34 , respectively, for a LDHP conduit system (1) embodiment (1L) and wellhead (10) embodiment (10L).
  • the inner second conduit (3L) may be hydraulically driven into the first conduit (2L), wherein additional spools (14) may be added to the upper end of the wellhead (10L).
  • a plurality of inner second conduits may be hydraulically placed into associated outer second conduits.
  • a lower end well casing (89) and lining (59L) are engaged below the pistons (130, 132) to secure and protect, or to case-off, the strata well bore (66), so as to prevent unintentional strata fracture initiation or propagation and/or strata bore instability during subsequent well operations.
  • At least the lower portion of the annulus between the strata bore (66) and casing (89) may be cemented using the lateral port (194L) and annuli (7) between loading surfaces (6L), once the lower piston (132) is urged below the lower end of the first conduit (2L) using the upper piston (130), annular spaces (7) and lateral openings (194L) against the upper seal (133).
  • hydraulic spools can be engaged to the upper end of the wellhead (10L) for use in pumping hydraulic fluid through lateral conduit (194) embodiments (194L).
  • the lateral conduit (194) embodiments (194L) may have selective pressure passageways (129) to various annular passageways (7) for communicating with circulating pistons (130) or fixed annular pistons (132), having associated seals (131) to trap pressure within the annuli (7) between the sealing loading surfaces (6L) and upper end installation seal (133), which may be removed from the first conduit head (17L) and replaced by a wellhead seal supported (e.g.
  • the second conduit (3L) can be urged axially downward within the first conduit (2L), when fluid is pumped into the lateral conduit (194L) using the pistons (130, 132).
  • the hydraulic pressure hoop force expands and compresses the associated pipe bodies (4) with associated loading surfaces (5,6) to facilitate the urging of one conduit within the other, such that when the hydraulic pressure hoop force is removed, the radial extending loading surfaces (6L) can abut to the circumferential loading surfaces (5) to share hoop stresses and to form a larger effective wall thickness that can be used to suspend one conduit within the other during installation.
  • a series of pistons (130, 132) may be placed at differing depths to allow the annuli of one piston (132) to exit the lower end of the first conduit (2L), or a different surrounding second conduit, to allow, e.g., cementing (134) of the conduit being urged within the strata bore (66) through the annular passageways, forced below the containing conduit pipe body (4) by using the shallower piston (130).
  • the shallower piston's annulus can be fillable with cement by using circulation (133) of the annuli (7) through selective fluid ports (129) to communicate between radial loading surface isolated annuli.
  • a second conduit's (3) radial extending loading surfaces (6L) are below the wellhead support (10LS), which may be slotted to accommodate such loading surfaces with the seal (133L) used for cementing, or it may be replaced with a special cementing seal which has injection and/or return circulation orifices and passageways through its body for cementing operations.
  • the second conduit head (18) embodiment (18L) shown as just the pipe body (4), may be sealed against the first conduit spool (17L) or another spool added to its upper end by using various pack-off and/or double olive (42) arrangements to seal and/or secure the upper end of the second conduit (3) within the wellhead (10L).
  • FIG. 38 an elevation cross section diagrammatic view of a slice through the strata is shown, which compares large diameter, high pressure conduit system (1) embodiments (IN, 1M) to existing (137, 138) well designs for an unconventional injection and production of well accessing, e.g., shale gas deposits.
  • Shale may become impregnated with hydrocarbon gas from the same sources as any hydrocarbon found in a more conventional deposit (144, 145, 149), e.g. permeable sandstone, wherein the hydrocarbons may have migrated (146) through more permeable strata from a source kitchen to the conventional deposit, and wherein shale gas may have migrated (147) through a less permeable formation, e.g.
  • fractured and/or leaking cap rock (148) comprising, e.g., relatively impermeable limestone, claystone, siltstones, and shale, into a more permeable and/or naturally fractured shale stone (142), which can be covered by a less permeable cap rock (143) or simply a more impermeable shale.
  • the present invention may be used to reduce the number of drilling site locations (IN, 1M) with a plurality of wells (136) from a single main well bore formed by a LDHP conduit system (1) and/or chamber junctions (21) which may use a plurality of multi-lateral whipstocks (135 of Fig. 38 , 46 and 48 of Figures 87-90 and 120-132 ), which also minimizes penetrations through the ground water system (152) compared to conventional wells (137, 138) having a single deviated or horizontal (111) well bore.
  • Single laterals (135) from a multi-well (136) LDHP conduit system (1M) may be used to replace a conventional well (137) practiced to provide pressure integrity for hydraulic fracturing (150).
  • a LDHP conduit system (1) is usable to provide, e.g., subterranean tanks, separators and heat exchangers to process production or to dispose of waste fluids comprising, e.g., mineral contaminated deep subterranean produced water or waste fluids produced during construction and production, comprising, e.g., slick water fracturing fluids.
  • waste fluids comprising, e.g., mineral contaminated deep subterranean produced water or waste fluids produced during construction and production, comprising, e.g., slick water fracturing fluids.
  • Production or injection through concentric or autonomous conduits of a LDHP conduit system (IN) into non-commercial subterranean formations (144) may be used to dispose of fluids and/or maintain subterranean pressures so as to urge migration (147) of fluids to producible formations (142).
  • wells of the present invention may be maintained and/or abandoned with small foot print rigs (51D), generally termed rig-less operations, to further minimise impact to, e.g., farm land (141).
  • Pressure integrity provided by chamber junctions and multi-lateral whipstock embodiments of the present invention may provide the same pressure integrity as a conventional well design for use in hydraulically fracturing (150) operations (139).
  • Conventional multi-lateral technology does not provide the necessary access, integrity and re-entry features, generally due to a lack of space or pressure bearing capacity.
  • a LDHP conduit system (1) allows batch operation reductions in well cost and improves recovery rates of, e.g., shale gas, using simultaneous hydraulic fracturing (150) across a plurality of wells through a single main bore with a single rig-up and rig-down of equipment.
  • Figure 39 illustrates an isometric view of a fracturable deposit strata slice, with a quarter section removed from the lower end of a LDHP conduit system (1) embodiment (1O), passing through the deposit diagrammatically.
  • the Figure illustrates hydraulic fracturing (150) of the strata in, e.g., shale gas or tight sandstone formations.
  • Figure 40 illustrates a piece of shale (142), its layering (152) and fracture orientation (77) to access a cross section of said layering, wherein fracture orientation depends upon the deposit in question and natural fracturing engagement or proximity to the artificial hydraulic fractures (77).
  • Pressure integrity is critical to the initiation and propagation of artificial fractures (77) using hydraulic force (150) because any fluid pressure leakage prior to the intended artificial fracture reduces the force (150) and, hence, the length of the induced fracture, thus limiting its effectiveness to place proppants and to extract fluids from a low permeability deposit. Because the pressure integrity of conventional multi-lateral technologies are generally insufficient or too complex, they are generally not used, and casing (89) lining (59O) are cemented (151) within well strata bores (66).
  • the LDHP conduit system (1O) is usable to provide a plurality of wells and/or lateral bores (66) from a single main bore, which can be cemented in place and can use conventional liner technology to enable and ensure pressure integrity for fracturing.
  • lower end perforations (108A) are made in casings and artificial fractures (77A) are hydraulically initiated and propagated (150) with, e.g., slick water and light sand proppants or more viscous gelled solutions that include larger sand proppants, depending upon the deposit characteristics, until the desired fracture length is achieved or screen-out occurs. Screen-out is when plugging of the proppants occurs, which is characterized by dramatic increase in pressure, and hydraulic fracturing is stopped.
  • Packers or screen-out caused by under displacement, may be used to isolate the lower artificial fracture (77A), and the process can be repeated by, e.g., perforating (108B) and then artificially fracturing (77B), followed by perforating (108C) and then artificially fracturing (77C), until a series of fractures is formed in a near horizontal (111), highly deviated or vertical well bore accessing a deposit.
  • perforating 108B
  • 108C perforating
  • 77C perforating
  • 77C perforating
  • FIGS 41, 42, 43 and 44 the Figures illustrate plan, elevation and two isometric views, respectively, of the application of a conventional well design to an unconventional shale gas deposit with well spacing.
  • the Figures show a well (137) bore (66) through subterranean strata with a vertical offset from well centre of approximately 1000-2000 metres and a substantially horizontal section (111), of approximately 500-1500 metres, at a depth between approximately 1000 and 4000 metres.
  • a horizontal section of approximately 735 metres comprises a series of artificial hydraulic fractures (77) of approximately 100-500 metres lateral width and 25-50 metres vertical height, which extends from a cemented and perforated lining of the strata bore (66).
  • Figures 45 and 46 illustrate diagrammatic elevation and isometric views of a LDHP conduit system (1) embodiment (IP) usable to access a larger portion of a vertical (153) shale gas deposit to increase recovery through, e.g., simultaneous vertical (153) artificial hydraulic fracturing (77).
  • Simultaneous fracturing (77A1, 77A2, 77A3) can occur through axially autonomous well bores (34) exiting the single main bore of the LDHP conduit system (IP), wherein dedicated pumps may be placed on each axially autonomous (34) conduit well bore to provide fracturing pressures and pressure integrity, after which another vertical (153) set (77B1, 77B2, 77B3) of simultaneous artificial fractures may be initiated and propagated to place proppants and stimulate production.
  • waste fluids from artificial fracturing (77) or natural fluid production may be injected back into the strata through another autonomous well bore or annulus to disposal fractures (77D) of a natural or artificial nature.
  • bores (66) of either a lateral (135) or multi-well (136) nature may be lined and cemented to provide equal pressure integrity to that of conventional single bore well designs (137), thus allowing for a plurality of wells or laterals from a single main bore and ground water formation penetration.
  • Figures 47, 48 and 49 depict diagrammatic isometric, elevation and plan views of various well trajectory of LDHP conduit system (1) embodiments (1Q), (1R) and (1S), respectively, illustrating various lateral whipstock, autonomous conduit (34) and/or side-pocket whipstock (33, 33A, 33B) well bore (66) arrangements, which can be usable to develop shale gas deposits or other low permeability formations that require artificial hydraulic fracturing (77) and/or fractures (77D) for waste fluid disposal.
  • Lateral and autonomous (34) well bores, from a single main bore conduit system (1Q, 1R, IS), may extend vertically (153 of Figures 45-46 ) or laterally (155) to intersect strata formations and/or natural fractures (154) to form a fracture matrix through their intersection with artificial fractures (77), to better recover fluids from a subterranean deposit.
  • Figures 50, 51 and 52 illustrate a plan view with line S-S, an elevation cross section across line S-S with a detail line T, and a magnified detail view within line T, respectively, of a LDHP conduit system (1) embodiment (1T) and wellhead (10) embodiment (10T) with a snap-together connector (49) embodiment (49A) forming part of a conduit hanger spool (14) embodiment (14T).
  • a second conduit (3) embodiment (3T2) is adjoined to another second conduit (3) embodiment (3T1) which is adjoined to a first conduit (2) embodiment (2T) with the abutment of loading surfaces (6) radially extending from a pipe body (4) against circumferential loading surfaces (5) of the adjacent pipe bodies (4) to form a larger effective wall thickness (9) sharing hoop stresses between conduits (2T, 3T1, 3T2).
  • the effective wall thickness (9) across the conduits (9T1) or across a conduit head (9T2) subassembly (17, 18), or a hanger spool (14), is usable to control the pressure bearing capacity, wherein the effective thickness (9T2) may be increased by, e.g., increasing the minimum wall thickness of the conduit head spool (18T2).
  • the various conduit heads (17, 18) and spools (14) may be secured (15) and sealed (16) by any means suitable to secure components and contain pressures; which are shown as seal rings (159A, 159B, 160A, 160B, 160C) in receptacles (163), threads (158), bolted (156) flanges (161), bolted (156) clamps (157) and snap together mandrels (49, 49A) onto which, e.g., valves, valves trees and/or other apparatuses may be engaged using hoop stress engagement.
  • Load shoulders (164) within the hanger spool (14T) may be used to hang, e.g., production and injection conduits, wherein any means of hanging conduits, such as conventional and prior art olive arrangements, may be used.
  • Placement of the LDHP conduit system (1T) may occur by forming a bore hole in strata (66 of Figure 53 ) and placing the first conduit (2T) after which another strata bore may be formed below the lower end thereof for placement of a second conduit (3T1, 3T2) which may extend below the lower end of a previously placed conduit such that radially extending loading surfaces (6) extend to associated circumferential loading surfaces of the previously placed conduit, wherein loading surfaces may be a smooth, radially extending, helically radial extending ( e.g. 6J of Figure 18 ) or have other suitable shapes abutted together so as to form an annulus space between conduits fillable with, e.g., fluids, cement or swellable materials to share hoop stresses and increase the effective wall thickness (9).
  • a piston may be engaged to the lower end of the conduits (2, 3) with the lateral port (194) embodiment (194T) used to provide hydraulic pressure to the piston and pipe bodies (4) to affect the effective loading surface diameters using hydraulic expansion and compression of conduits during insertion, after which pressure may be released to abut and adjoin one conduit to another for sharing hoop stresses.
  • the radial loading surfaces (6T1, 6T2 of Figures 53-54 ) may be passed between splines (162 of Figure 54 ) in conduits heads (17, 18) which may seal ( e.g.
  • the weight of the conduit (3) string extending axially below the wellhead may be used to provide hoop force placement, abutment and adjoining of conduits.
  • a drive head may also be secured to the conduit (3T1, 3T2) to forcibly hammer the conduit downward, thus forming hoop forces to place, abut and adjoin two conduits, after which the drive head may be removed and the casing head installed.
  • Gravity cementing of the annulus through the lateral conduit (194, 194T1, 194T2, 194T3) may be undertaken or conventional cementing with return circulation through the annulus and lateral conduit passageway may occur.
  • Figure 53 and 54 are isometric and exploded views of the LDHP conduit system (1) embodiment (1T) of Figure 50 , illustrating a first conduit head (17) subassembly embodiment (17T) engaging a lower end first conduit (2T) to a second conduit head (18) embodiment (18T1) with an associated second conduit (3T1) engaged to another second conduit head (18) embodiment (18T2) about an associated additional second conduit (3T2), engaged therein.
  • Conduits (2T, 3T1, 3T2) may be sequentially placed at ever increasing depths to form an effective wall thickness across any combination of conduits to, in use, meet the pressure bearing requirements of the conduit system at a required depth, after which one or more wells may be concentrically and/or axially autonomously (34) urged through the subterranean strata communicating with a single bore valve tree engaged to each wellhead connector (49A) or a valve tree with a plurality of bores engaged to all of the wellhead connectors (49A) to further control fluid communication.
  • a plurality of axially autonomously (34) or parallel wells may be bored through the large diameter high pressure single main bore formed by the conduit system (1T).
  • One or more wells are placeable through the concentric bore of the conduit system (1T), e.g., a chamber junction and/or axially autonomous (34) well conduits passing through the illustrated conduit hanger (14T).
  • a conduit hanger (14) may comprise any conduit hanger system supported by, e.g., first (17) and second (18) conduit head subassemblies, to access subterranean strata passageways.
  • the space between the single main bore of the conduit system and the one or more well conduits therethrough may be used for fluid processing, e.g. the separation arrangement of Figure 17A , or as a heat exchanger.
  • the natural subterranean insulation and heat retaining properties of the sub-mudline strata may be used with a LDHP conduit system (1) separator (11), wherein separated water may be released to the ocean provided it has low hydrocarbon concentrations and/or other toxic material, with heat transferred by a heat exchanger (12) within the LDHP conduit system (1) during separation providing flow assurance for pipeline transportation.
  • a pump may be used for separated water disposal within the subterranean strata through a separate axially autonomous conduit passageway extending from the conduit system (1).
  • conduit routing placeable within the main bore of the LDHP conduit system (1T) may communicate with the smaller diameter conduit orifices of a conduit hanger (14T) hung from load shoulders (164 of Figure 50 ).
  • Olive seal arrangements may extend to fluidly producible and/or injectable subterranean strata to form autonomous wells, separators and/or heat exchangers to carry out fluid processing, wherein any variation of suitable control, measurement and/or pumping apparatus engageable to the system may be used.
  • a LDHP conduit system is analogous to a blank canvas or empty pressure bearing subterranean tank (13) within which any manner of well construction apparatus may be placed and within which any method may be used, wherein not only separators (11) and heat exchangers (13) are possible, but also inventions of the present inventor and various conventional flow control devices combinable with, e.g., wellhead devices, valve tree devices, casing shoe devices, straddle devices, plug devices, sliding side door devices, frac sleeves, dropped object activated devices, remotely controlled devices, gauges, control lines, cable, acoustic, fluid pulse controlled or data collection devices, pressure activated valve devices, gas lift valves, surface valves, insert valves, flow control devices, hangers, void access devices, control line pass-through devices, packers, seal stacks, motors, fluid pumps, subsurface valves, chokes, one-way valves, venturi devices such as velocity or jet pumps usable with various connectors, and/or sealing devices.
  • separators (11) and heat exchangers (13) are
  • manifold crossovers may be included with flow mixing devices, such as venturi or jet pumps, sliding side door or gas lift valves, which are further usable with chamber junction crossovers, chamber junction manifolds, well junctions and slurry passageway apparatus radial passageways to fluidly communicate between passageways.
  • Additional apparatuses for engaging or communicating with a passageway through subterranean strata can be usable with various flow controlling devices to selectively control and/or separate simultaneously flowing fluid mixture streams of varying velocities within a LDHP conduit system (1).
  • Constructing a plurality of passageways to pressurized subterranean regions through a single main bore drives a practical need for placing a plurality of cable and subterranean valves within a large diameter high pressure containment system that are easily accessible without repeated large scale rig-up and rig-down, or mobilization and demobilization of rigs.
  • the need for control lines and valves increases with subterranean separators and downhole placement of other processing equipment for measuring and monitoring, and wherein maintenance must include replacing valves and/or other flow control devices usable to control fluid communication and/or pressures within a well with a plurality of passageways.
  • a large diameter high pressure conduit system (1) may be formed to house a plurality of axially concentric well bores and/or axially autonomous well bores through a wellhead (10) to form a high pressure containment space within which manifold string arrangements and manifold crossovers of the present inventor may be used with valves, flow control devices and/or other flow controlling and/or measurement devices and lines, which are usable in various configurations and arrangements with standardized apparatuses.
  • One or more selectively controlled pressurized fluid mixture flow streams from one or more substantially hydrocarbon and/or substantially water wells through a single LDHP main bore may be constructed and operated as further demonstrated within the remaining Figures for any conduit size.
  • Figures 55, 56 and 57 show an elevation view with section lines U-U and V-V and break lines presenting removed portions shown along axis, a plan view along section line U-U with dashed lines showing hidden surfaces, and another plan view along line V-V, respectively, of a large diameter high pressure conduit system (1) embodiment (1U).
  • An associated high pressure chamber junction (21) embodiment (21U) is illustrated with an exemplary LDHP conduit system (1), wherein a 183 cm (72") outside diameter first conduit (2) embodiment (2U) with the internal circumferential loading surface (5) abuts against load surface (6) embodiments (6U1) radially extending from a 168 cm (66") outside diameter second conduit (3) embodiment (3U1), with an internal diameter loading surface abutted against loading surface (6) embodiments (6U2) radially extending from a 152 cm (60") outside diameter of another second conduit (3) embodiment (3U2), with the internal diameter loading surface abutted against loading surface (6) embodiments (6U3) radially extending from a 137 cm (54") outside diameter of a second conduit (3) embodiment (3U3).
  • the associated radial extending loading surfaces (6U1, 6U2, 6U3) abut to the inner diameter circumference loading surfaces to adjoin pipe bodies of the conduits (2U, 3U1, 3U2, 3U3) and form a greater effective wall thickness (9) embodiment (9U), greater than the sum of the 5.7 cm (2 1 ⁇ 4") pipe body (4) wall thickness, due to the sharing of hoop stress resistances between pipe bodies.
  • embodiments of the present invention are capable of greatly exceeding a 137 cm (54") conventional single main bore well design, wherein it is the general practice to design two internally unsupported concentric conduits with fluid annuli.
  • the production annulus of a 137 cm (54") conduit with 5.7 cm (2.25") wall thickness 551.6 N/mm2 (80-ksi) material could adequately bear 402.2 bar (5833-psi) burst and 219.7 bar (3186-psi) collapse pressures; whereas, even at unrealistically low efficiencies, an effective wall thickness (9) formed through sharing of hoop stresses and abutment of loading surfaces during sequential adjoining of conduits will always be greater than a fluid filled annulus where abutment is absent.
  • the nature of the loading surfaces (6) and annular spaces (7) may be adjusted with, e.g., malleable metals, supported with swellable elastomers or cement, to design the desired wall thickness, efficiency, size and number of adjoining conduits needed to meet the pressure bearing capacities without losing the conventional need for a fluid filled annulus that may be monitored, as shown in Figures 34 to 37 .
  • the final internal diameter desired for axially concentric and/or axially autonomous conduits and/or subterranean processing and flow control or mixing apparatuses may be achieved and various methods to optimise fluid communication of producible and/or injectable fluids between a wellhead and the subterranean strata may be used.
  • 51 cm (20") and 41 cm (16") well casing (89) embodiments may extend downward from the 61 cm (24") exit bore of a chamber junction formed within the single main bore adjoined conduits (2U, 3U1, 3U2, 3U3).
  • a 17.8 cm (7") casing embodiment (59U2) is also placeable through the bore of a 24.4 cm (9.625") casing extending from the chamber junction.
  • FIGS 58 and 59 show an elevation view with section line W-W and a plan along line W-W, respectively, with break lines along axially downward conduits indicating removed sections of a large diameter high pressure conduit system (1) embodiment (1V).
  • Loading surfaces may be placed on a high pressure chamber junction (21) embodiment (21V) with a snap-together connector (49) embodiment (49B).
  • the exemplary LDHP conduit system (1) sizing illustrates a 152.4 cm (60") outside diameter second conduit (3) embodiment (3V3) abutted against another 137 cm (54") outside diameter second conduit (3) embodiment (3V2) abutted against another 123 cm (48") outside diameter second conduit (3) embodiment (3V1), wherein each have 5.7 cm (2 1 ⁇ 4") wall thicknesses with radially extending load surfaces (6V1, 6V2, 6V3) within inside diameter load surfaces (5) forming adjoined pipe bodies (4) with greater effective wall thickness (9V).
  • the arrangement provides 47.6 cm (18.75”) ID axially autonomous (34) conduits usable for axially concentric (35) conduit placement of, e.g., conventional well conduit sizing of 34 cm (13.375") outside diameter (OD) casing with a 31.4 cm (12.347") inside diameter (ID), 24.4 cm (9.625") OD casing with a 21.7 cm (8.535”) ID, and 17.8 cm (7") OD casing with 15.25 cm (6.004") ID.
  • Such casings may be conventionally hung with liner hangers (106 of Figure 17A ) within the 47.6 cm (18.75”) (59V2, 59V4) ID extending from and placed with the 122 cm (48") pipe body OD chamber junction (21V) using, e.g., 50.8 cm (20") OD casings (89), together with supporting 24.4 cm (9.625") OD casings (89, 59V1, 59V3), wherein the casings may be cemented using circulation through the independent well bores, or a large bore may be drilled for the arrangement embodiment (49B) of hydraulically actuated snap together hoop stress connectors (49), which may be used to simultaneously run axially autonomous (34) conduits which may be cemented with the bore as a unit.
  • Sealable hydraulic ports (166) forming part of the connectors (49) and arrangement (49B) may be used to simultaneously operate snap together connections for simultaneous connection of the embodiment (49B). Such arrangements are not practiced nor would they be obvious to practitioners in an industry reliant on lower cost screw couple connectors, who rarely use snap together connections.
  • Embodiments of the present invention may snap together a plurality of connectors simultaneously as part of axially and circumferentially autonomous (34) conduits usable to form a plurality of wells in the embodiment (IV), whereby a subterranean processing system may also use seal stacks and polished bore receptacles within such snap together arrangements.
  • Figures 57 and 59 also show optional central single bore accesses (165) of 47.6 cm (18.75”) and 54 cm (21.25") diameters to suit various sizes of risers and blowout preventers (BOPs, 90 of Figure 14 ) usable with a chamber junction and bore selector, as depicted in Figures 60-61 , 76-81 and 93-105 .
  • a hanger spool (14) with a corresponding orifice may be used, or, alternatively, a hanger spool (14) with a plurality of access orifices, e.g. (14T of Figures 50-54 ) may be laterally skidded between the bores.
  • Manifold and chamber junction crossovers described in Figures 62 to 75 may also be used to transition from axially concentric (35) to axially autonomous (34) conduits for fluid and apparatus communication using central bore access (165) to the axially downward disposed bores (e.g. 59U1, 59U2, 59U3, 59V1, 59V2, 59V3, 59V4).
  • Figures 60 and 61 illustrate an orthographic tilted isometric view of the vertical section through line AL-AL view of Figure 94 with detail line X and a magnified view within detail line X, respectively, wherein the vertical scale is skewed from the lateral scale to provide a single view of the long LDHP conduit system (1) embodiment (1Y) illustrated across Figures 94-105 .
  • the LDHP conduit system (1Y) may form a subterranean tank (13) embodiment (13Y) with internal components comprising a subterranean separator (11) embodiment (11Y) and heat exchanger (12) embodiment (12Y) formed with a manifold crossover (20) embodiment (20Y), chamber junction (21) embodiment (21Y) and loading surface high pressure chamber junction (21) embodiments (21Z1, 21Z2 and 21Z3) using snap-together connector (49) embodiment (49C, 49D, 49E, 49F, 49G) arrangements, which are associated with Figures 93 to 105 and component parts shown in Figures 66 to 92 . Fluids from a plurality of wells may be processed within the single main bore, wherein access and process conduits may form a plurality of barriers to the environment and simultaneously flow various fluid streams.
  • Figures 60-105 may be used with the embodiments of Figures 1-4 , 34-39 and 45-49 , or the arrangement may be adapted for wellhead access through circumferentially (34) autonomous conduits placed substantially parallel through the inside diameter of a LDHP conduit system (1Y), similar to the embodiments of Figures 14-17 , 17A and 17B , 50-54 .
  • various large diameter high pressure conduits (3, 3Y1) may be adjoined with LDHP conduit assemblies (3Y2) placed with a lower end chamber junction (21Z1, 21Z2 and 21Z3 of Figures 76-81 ) engaged together with snap connector embodiments (49E, 49F, 49G) to axially and circumferential autonomous conduit (34) bundles (34Y of Figures 82-83 ) connected with snap together embodiments (49G) to provide a centralized conduit access system for urging subterranean bores axially downward using drill strings, casing strings (187, 186, 185, 182) and various other apparatuses comprising, e.g., liner hangers (167, 167A, 167B, 167C) or concentric (35) polished bore receptacles (PBR, 168).
  • liner hangers 167, 167A, 167B, 167C
  • PBR polished bore receptacles
  • the plurality of wells may be completed with, e.g., seal stacks (169) inserted into PBR's (168) connected to manifold crossovers (20Z, 20Y) or, alternatively, using production tubing hung from a spool (14T of Figures 50-54 ) when parallel autonomous bores (34) are used rather than central access manifold crossovers (20).
  • seal stacks (169) inserted into PBR's (168) connected to manifold crossovers (20Z, 20Y) or, alternatively, using production tubing hung from a spool (14T of Figures 50-54 ) when parallel autonomous bores (34) are used rather than central access manifold crossovers (20).
  • a series of axially and circumferentially autonomous conduit (34) bundles (34X) may be engaged with hoop stress connections comprising, e.g., snap together connections (49C), which may be engaged (49D) to a LDHP chamber junction (21Z1 and 3Y2) as shown in Figures 87-90 .
  • Well casings (182, 185, 186, 187) may be conventionally hung within the conduit bundles (34X) with liner hangers (167, 167A, 167B, 167C) and still provide annulus access through orifices (189, 190, 191), which may be closed with straddle packers (e.g. 15E of Figure 119E) provided by the passageway access of conduit (188), or the orifices may be left open to fluidly communicate with annuli under the liner hangers to circulate during cementing operations and/or monitor annuli pressures.
  • casings may be hung concentrically one inside the other, e.g.
  • concentric conduits (182, 185, 186, 187) may also have axially extending loading surfaces (6) abutting one to another to share hoop stresses and form a larger effective wall thickness, wherein one or more axially autonomous (34) concentric conduit groups (182, 185, 186, 187) may be used.
  • axially and circumferentially autonomous (34) well bores of concentric (35) conduits may simply be disposed in an axially parallel configuration passing through a single main bore of the LDHP conduit system (1).
  • (3411) and (3412) of Figure 17A and well bore (59Y1) conduit (188) of Figure 60 may simply pass through a single main bore, dependent upon the well application and associated need.
  • the additional costs of moving a BOP (90 of Figure 14 ) between axially autonomous (34) well orifices in a conduit hanger spool e.g. 14T of Figures 50-54
  • the arrangement described in Figures 60-105 whereby single bore access operations through a subsea tree (53) with an offshore rig (51C) may be preferable.
  • a three valve (2411, 2412, 2413) manifold crossover (20Z) arrangement may be engaged with a manifold crossover (20Y) and chamber junction crossover (21Y) usable for controlling individual separator inlets for each of the well bores (59Y2, 59Y4, 59Y6) using diverting devices (25) like plugs (e.g. 25A of Figure 119A ).
  • Valve trees with a plurality of bores or a plurality of valve trees stacked vertically or arranged as horizontal trees may be used.
  • Sliding side doors, valve side pocket mandrels and/or any other method or apparatus may be applied to each well to exchange fluids between any particular well bore and the tank (13Y) through which a bore may pass.
  • Any manner of control or data acquisition may be placed about or within conduits or the tank to allow manual or computer monitoring and control.
  • Axially autonomous (34) wells passing through the single main bore may act as heat exchanger tubes to exchange or take heat from the fluids in the tank (13Y).
  • Various annulus access mechanisms may be used to access the tank, wherein the tank's plurality of walls (2, 3) act as primary and secondary high pressure barriers.
  • Well entry into the tank (13Y) may be provided with various methods, such as packers (167), polished bore receptacles (168) and seal stacks (169).
  • the tank (13Y) may also have baffles (170) or spreaders (30) used for aiding the separation of fluid densities, wherein the baffles or spreaders may also engage axially autonomous conduits (34), usable as heat exchanger (11Y) tubes, to secure such conduits and prevent vibration, better facilitate bundled installation of conduits and/or guide installation or removal of conduits used during well construction and maintenance.
  • Fluid access to the tank (13Y) may be accomplished with any number of ported assemblies (192), sealable with e.g. straddles or valves, through an axial autonomous conduit (e.g. 188), or through a chamber junction with a bore selector or kick-over tool.
  • Various accesses to the tank (13Y), for the purposes of mixing, separation, heat exchange or other fluid processing tasks during drilling, completion and/or production may be accomplished through ports (193) in a central access (e.g. adjacent to 20Y).
  • a central access system of chamber junctions and/or manifold crossovers and manifold strings can be usable during drilling or completion and production, wherein a central access may be used for drilling, but removed prior to completion and production, or vice versa. Additionally, there may be combinations of vertical access and lateral access comprising, e.g., a side pocket drilling whipstock with a kick-over arrangement for boring one or more laterals from the main bore.
  • Figures 62, 63 and 64 show a plan view with section line Y-Y and dashed lines showing hidden surfaces, an elevation section view along line Y-Y and a projection of the elevation section Y-Y view, respectively, of a large diameter high pressure conduit system (1) embodiment (1AA) with an adapted three flow stream manifold crossover (20) separator inlet (26) with a diverter plate (29) embodiment (20W), illustrating how the flow (171, 173, 174) through conduits (59W1, 59W2, 59W3) may be diverted with a diverting device, e.g.
  • FIG 65 a diagrammatic elevation view of a large diameter high pressure conduit system (1) embodiment (1AB) with a three flow stream adapted manifold crossover (20) separator inlet (26) and diverter plate (29) embodiment (20AA), is shown depicting similar flow streams to the arrangement (20Y) shown in Figures 66 to 68 , wherein the outermost annular flow stream (174) may be diverted to the tank (13), heat exchanger (12) or separator (11) through an inlet (26) to engage a diverter (29), used to disperse fluid and resist, e.g. erosion, while inner flow streams (171 and 173) can crossover over at various points, using diverting devices (e.g. 25E of Figure 119E) to a fluid processing tank (13) or separator (12) inlets (26), using diverting walls within the passageways of concentric (35) conduits (179, 180, 181).
  • diverting devices e.g. 25E of Figure 119E
  • Figures 66, 67 and 68 a plan view with section line Z-Z, an elevation cross section view along line Z-Z with break lines indicating removed sections and a projected view of the elevation section view along Z-Z, respectively, of a manifold crossover (20) embodiment (20Y) depicting separator inlet (26) and diverter plate (29) for diverting fluids through concentric (35) conduits (179, 180, 181) with flow control devices (e.g. 25A of Figure 119A ) which transition between smaller and larger diameters, as shown in the upper and lower break lines, wherein a larger diameter (178) is used about straddle nipples (175) and diverting devices (25) to control flow velocities and minimize erosion.
  • An arrangement e.g.
  • plugs and straddles may be placed to selectively control the flow of fluids through the manifold crossover into the tank, separator or heat exchanger, wherein installation or removal of various flow diverting devices may selectively cause crossover. Access and placement of devices may occur through the inner most bore using, e.g., cable deployment apparatuses.
  • the flow control crossover (20Y) is further illustrated within the LDHP conduit system (1Y) across Figures 94 and 95 .
  • FIG. 69, 70, 71 and 72 an isometric view, plan view with section line AA-AA, an elevation cross section view along line AA-AA with break lines showing removed portions and a projection of the elevation cross section along line AA-AA, respectively, of a simultaneous flow manifold crossover (20) chamber junction (21) embodiment (21Y) of the present inventor, are shown.
  • FIGS. 1-10 illustrate how axially autonomous (34) conduits (182, 183, 184) may be transitioned to axially concentric conduits (179, 180, 181) by enlarging and sectioning (203) the annuli of the concentric conduits about the chamber of a chamber junction (21), wherein a lower passageway (204) may connect a conduit and a sectioned-off annulus which is extended to an axially upward annulus entry passageway (201, 202) for each of the respective axially autonomous and axially concentric conduits to direct flow from a unique conduit to a unique annulus.
  • Access to the lower end conduits (182, 183, 184) can be maintained through the chamber junction (21Y) and the use of a bore selector, wherein the chamber junction fluid crossover manifold can be actuated by placing plugs (e.g. 25A of Figure 119A ) in each of the conduits (182, 183, 184) at the chamber junction bottom level to divert (25) fluid from the conduits to their associated annuli, without mixing of the fluids in any of the axially autonomous conduits, as shown in Figure 97 , when the plugs are in place.
  • plugs e.g. 25A of Figure 119A
  • Figures 73, 74 and 75 show a plan view with section line AB-AB, the upper end of the elevation cross section view along line AB-AB and the lower end of elevation cross section view along line AB-AB, respectively, wherein the upper end of Figure 75 is a continuation of the lower end of Figure 74 , showing a simultaneous flow manifold crossover (20) embodiment (20Z) of the present inventor, wherein three subsurface safety valves (24) may be arranged such that the flow within each of the passageways can be controlled by one of the safety valves with flow crossing over at each flow diverting apparatus (25, e.g. 25A o Figure 119A ), which may be removed to allows access through the central passageway to axially autonomous passageways (e.g.
  • Each of the flow streams may be controlled with individual safety valves (24Z1, 24Z2, 24Z3) and associated control lines (200), which are also shown in Figure 96 , wherein the control lines may also bundled (200B) into a multi-line umbilical, as shown in Figure 95 .
  • the lower safety valve (24Z3) is controlled by a hydraulic control line (200) fed through a three way manifold crossover (20Z1), which is similar to the crossover (20W) of Figures 62-62 without an outlet (26) and diverter (29).
  • Control line passageways feed through (176) axially upward until they are adjacent to the hydraulic control line (200) of the intermediate valve (24Z2), which also extends upward until they enter two way manifold crossover (20Z2).
  • Control line feeds through (176A, 176B) and continues axially upward to become parallel with the third safety valve (24Z1).
  • Hydraulic control lines (200) may be passed through the various subterranean components to provide the necessary information and control for subterranean processing.
  • Cabling and/or controls may also be tied back through a conduit with a wet connector.
  • Wet connectors similar to those of remote operated vehicles (ROVs) and underwater cameras are usable within pressurized environments, well bore conduits or a tank of the present invention, wherein wet-mateable connections may be made in a fluid environment.
  • wet connections may be placed within an axially autonomous conduit (e.g. 188 of Figure 60-61 ) during or after well construction, wherein a connector and trailing wire may be pumped down the conduit to and plug into an associated wet connector.
  • An apparatus with a trailing umbilical cable may be pumped down within various conduit of a LDHP conduit system to operate, e.g., cameras, cutting devices, or gauges which removes the need to pass hydraulic control cables through various apparatus (176, 176A, 176B) while allowing maintenance within subterranean pressure and temperature conditions.
  • FIGS 76 and 77 a plan view with line AC-AC and an isometric cross section along line AC-AC of Figure 76 , show a LDHP conduit system chamber junction (21) embodiment (21Z1) with upper end snap-together connector (49) and PBR (205) embodiment (49E) engageable with the lower end of Figure 78 , showing how a single central chamber (59Y7) and three autonomous well bore conduits (59Y1, 59Y3, 59Y5) may be transitioned to a lower end snap-together connector (49) embodiment (49D) of six autonomous conduit well bores (59Y1-59Y6), which may be simultaneously coupled via hoop stress connectors.
  • LDHP conduit system chamber junction (21) embodiment (21Z1) with upper end snap-together connector (49) and PBR (205) embodiment (49E) engageable with the lower end of Figure 78 showing how a single central chamber (59Y7) and three autonomous well bore conduits (59Y1, 59Y3, 59Y5) may be transitioned to a lower end snap-together connector (49) embodiment
  • Figures 78 and 79 show a plan view with line AD-AD and an isometric cross section along line AD-AD of Figure 78 , depicting a LDHP conduit system chamber junction upper end (21) embodiment (21Z2) with an upper end snap-together connector (49) and PBR (207) embodiment (49F), showing a lower end mating seal stack mandrel (206) and snap connector (49) embodiment (49E) usable for simultaneously connecting conduits to the upper end of Figure 77 .
  • Figures 80 and 81 show a plan view with line AE-AE and an isometric cross section along line AE-AE of Figure 80 illustrating a LDHP conduit system chamber junction upper end (21) embodiment (21Z3), with an upper end snap-together connector (49) and PBR (207) embodiment (49G), engageable to the lower end of Figure 83 , and a lower end mating seal stack mandrel (208) and snap connector (49) embodiment (49F) engagable to the upper end of Figure 79 .
  • Figures 82 and 83 show a plan view with line AF-AF and an isometric cross section along line AF-AF of Figure 82 , which depicts an embodiment (34Y) of a LDHP conduit system, with axially autonomous conduits (34) with upper end snap-together connectors (49) and PBR (207) embodiment (49G) engageable with the lower end of other axially autonomous conduit embodiments (34Y), wherein a lower end mating seal stack mandrel (209) and snap connector (49) may simultaneously connect the multiple conduit embodiment (49G) to the upper end of Figure 81 .
  • FIG. 84, 85, 86 and 86A a plan view with line AG-AG, a cross section elevation view along line AG-AG, an exploded view with detail line AX and a magnified detail view within line AX, respectively, of a LDHP conduit system are shown.
  • the LDHP system includes axially autonomous conduits (34) and manifold crossover (20) arrangement embodiment (34Z) with snap-together connector (49) embodiment (49D).
  • the Figures illustrate large diameter conduits (221) between an upper end pin connector (210) and lower end box connector (211) forming well bore conduits (59Y2, 59Y4, 59Y6), and smaller diameter conduits (214, 216) on opposite ends of profiled nipple conduits (175).
  • the depicted arrangement is usable for engaging diverting devices, e.g. valves, straddles and plugs, at opposite ends of a ported (223) conduit (215) engagable with a lateral passageway (218) conduit (217) which is further engagable to a passageway (222) in the larger diameter conduits (221), wherein the smaller diameter conduits forming well bore conduits (59Y1, 59Y3, 59Y5) have smaller diameter pin (212) connectors at the upper end thereof and box (213) connectors at the lower ends. Additional conduit wall thickness (219) may be placed around orifices (223) to match the pressure bearing capacity of the smaller diameter conduits at the crossover point.
  • diverting devices e.g. valves, straddles and plugs
  • a simultaneous connection bracket embodiment (229) may be used for combining a larger diameter engaging mandrel (225) that engages the receptacles of a larger diameter box connector (211) and pin connector (210) receptacles (226), which includes a small diameter engaging mandrel (227) for engaging a smaller diameter box connector (213) and pin connector (212) receptacles (228), wherein the bracket (229) is usable to ensure that the inaccessible side of the snap together boxes (211, 213) are simultaneously coordinated with a clamping machine for simultaneously snapping together the connections.
  • Snap together boxes (211, 213) can be expanded with hydraulic pressure onto associated pins (210, 212), which can be compressed with the same hydraulic pressure applied through ports (166) during the process of simultaneously supplying hydraulic pressure to and snapping the six well bore conduits (59Y1-59Y6) together with a claiming machine that engages and snaps the boxes and pins together. Hydraulic pressure is then released and the profiles and hoop stresses of the connectors (210-213) secure the associated conduits together. Any arrangement of hydraulic hoses and/or clamping mechanisms may be used to operate the plurality of snap together connections (49, 49D) of the present invention.
  • the arrangement (34Z) may also comprise a large diameter second conduit (3) with loading surfaces (6) for abutting and adjoining the assembly to a first conduit (2) or another second conduit, wherein the supporting brackets (220) may be engaged to the second conduit (3), and wherein the number of brackets may be increased to further form a supporting matrix structure within the second conduit to further increase the burst and/or collapse bearing efficiency of the effective wall thickness by adding the support of the brackets therein.
  • Figures 87 and 88 depict an isometric view with detail line AH and magnified detail view within line AH of Figure 87 , of an embodiment (34X) of an LDHP conduit system having axially autonomous conduits (34), with an axial lower end (45) and lateral whip-stock (46) orifice exit embodiment (46Y), using a snap-together connector (49) embodiment (49D). Larger diameter well conduits (231) and smaller diameter well conduit (232) are shown between the chamber junction and whipstock.
  • Figures 89, 90, 91 and 92 show a plan view with line AI-AI, an elevation cross section view along line AI-AI with break lines representing removed portions and detail lines AJ and AK, a magnified detail view within line AJ and a magnified detail view within line AK, respectively, of a LDHP conduit system, having a lateral axially autonomous conduit (34) embodiment (34X) and a whipstock (46) embodiment (46Y) with a snap-together connector (49) embodiment (49D) associated with Figures 87 and 88 , showing the box (210) and pin (211) larger diameter snap together hoop stress connectors adjacent to box (212) and pin (213) smaller diameter pin connectors with associated brackets (229) for simultaneous connection.
  • An upper (229U) bracket (229) with large diameter engagements (225, 226) and small diameter engagements (227, 228) associated with a smaller diameter lower (229L) bracket (229) may be used to secure the upper box connectors (210, 212) so that they may be snapped into the lower pin connectors (211, 213) using a clamping machine engaged to the outwardly exposed receptacles (226, 228) of the boxes (210, 212) and pins (211, 213).
  • the clamp can snap the connection after applying hydraulic pressure to expand the boxes and compress the pins via hydraulic ports (226) between the pins and boxes via connected hydraulic hoses and hydraulic power pack.
  • abutment of the first (2) and second (3) conduits uses the friction of an axial length of a loading surface abutment hoop stress sharing to resist movement during installation
  • an olive and dual olive arrangement uses the containing hoop stresses against a shorter axial frictional length of two smooth surfaces
  • hoop stress connectors use engagement of teeth across a unique pattern, to ensure that the connectors are fully engaged.
  • Prior art snap together connections described herein can be assembled quickly, but any suitable connection comprising, e.g., field welding, dog or mandrel and profile engagements, clamped flanged and/or flanged and bolted connections, or rotary screwed connectors spun within a clamped frame may be used provided that a plurality of axially autonomous connections can be made.
  • snap together connections using hoop stresses may have burst, collapse and axial loading capabilities greater than the conduits to which they are fixed; hence, it is important to ensure a good connection between the connectors and pipe body with suitable welding (230).
  • the effective wall thickness of prior art snap connectors may be downsized when included within first (2) and second (3) conduits of a LDHP conduit system (1) to better facilitate installation, since the connector does not need to bear hoop stresses independently and may gain strength from surrounding conduits, hence snap connectors may be used more for their axial bearing capacity, sealing and installation than burst and collapse rating.
  • first (2) and/or second (3) conduit embodiments they may also have loading surfaces matching the loading surfaces of the conduits on which they are welded (230) to ensure axial continuity of the loading surface abutments and effective wall thicknesses. If threaded connections are used for first (2) or at least second (3) conduits, any of the various means of placing loading surfaces over the connectors may be used over a connector upset or flush connection. The loading surface across such connections may be profiled or flush using clamping, pinning, bolting or field welding.
  • the claimed simultaneous connection of a plurality of axially and circumferentially autonomous (34) well bores (59Y1, 59Y3, 59Y5) and axially autonomous (34) well bores (59Y2, 59Y4, 59Y6) may share circumferences during chamber junction transitions (21Z1), such that the conduits (182, 185, 186, 187), conduit hangers (167A, 167B, 167C) and PBR (168) of Figures 60 and 61 , and manifold crossovers (20Y, 21Y, 20Z) of Figures 66-75 may be placed and engaged with a plurality of simultaneously coupled snap-together hoop stress connectors, interlocking brackets (229), clamps, hydraulic ports (166) and PBRs (205, 207) with associated mandrel seal stacks (206, 208, 209), wherein such an arrangement could not be obvious to practitioners accustomed to single concentric bore well designs.
  • Figure 93 is a plan view with line AL-AL
  • Figures 94 to 105 are elevation cross sections along line AL-AL, wherein the upper end of Figure 95 is a continuation of the lower end of Figure 94 , and the upper end of Figure 96 is a continuation of the lower end of Figure 95 , and so on, to the upper end of Figure 105 which is a continuation of the lower end of Figure 104 .
  • Figures 93 and 94 to 105 illustrate the LDHP conduit system (1) embodiment (1Y) with a subterranean tank (13) embodiment (13Y) with an internal subterranean vertical separator (11) embodiment (11Y), heat exchanger (12) embodiment (12Y), manifold crossover (20) embodiment (20Y, 20Z), manifold crossover chamber junction (21) embodiment (21Z) and loading surface high pressure chamber junction (21) embodiment (21Z1, 21Z2, 21Z3) arrangement of the snap-together connector assembled (49) embodiment (49D, 49E, 49F, 49G) component parts of Figures 66 to 92 , which can be associated with the orthographic tilted isometric views of Figures 60 and 61 .
  • Figures 93 to 105 illustrate adjoined second conduit (3) embodiments (3Y1, 3Y2, 3Y3) with loading surfaces (6) abutted to circumferential loading surfaces (5) having intermediate annuli (7) to form a greater effective wall thickness (9) embodiment (9Y) hoop stress sharing arrangement, usable as a subterranean separator (11), heat exchanger (12) and/or tank (13).
  • Subterranean bores are formed and the first and second (3, 3Y1, 3Y2, 3Y3) conduits are placed to form a LDHP chamber junction (21, 21Z1, 21Z2, 21Z3) using autonomous conduit bundles (34Y) that may be accessed via a bore selector (e.g. 25D of Figure 119D ) for placement of further conduits (187, 186, 185), wherein the lower end of each successive conduit may be placed deeper.
  • a screwed box (238) and pin (239) rotary connector may be used for ease of connecting first and second (3, 3Y2) conduits or snap connectors or other suitable connections may be used if first and second conduits which may installed individually or together as described in Figures 12 and 12A .
  • a cementing shoe may be added to the lower pin (239) end of second conduit (3Y2).
  • conduit (187) may be placed and secured therein to form well bore conduit (231) of a conduit bundle (34X) with a liner hanger (167) assembly (167A), wherein cementing may use lateral passageway (217) manifold crossover between a smaller conduit (232) of well bore (59Y1) and larger conduit (231) of well bore (59Y4), which may form part of conduit bundle (34Z) or may use the lower end of conduit (232) whipstock assembly (46Y) for conventionally cementing around the liner hanger (167).
  • a cross over passageway (217) When a cross over passageway (217) is not being used, it may be covered with a straddle (e.g. similar to. 25E of Fig. 119E) engaged in a nipple (175).
  • Well bores (59Y1, 59Y3, 59Y5) may be used to support fluid operations on well bores (59Y2, 59Y4, 59Y6) which may be transitioned to a central bore (59Y7), or alternatively may have autonomous well bores (59Y1, 59Y3, 59Y3), accesses usable with liner hangers (167), PBRs (168) and/or other downhole boring and casing or lining equipment.
  • drilling fluids injection of fluids for waste disposal or water flood or production of fluids from the subterranean strata during or after well construction may be processed within the tank (13) or separator (12) accessible with, e.g., cables, tools, cameras or other apparatuses usable within a subterranean environment for well construction, production, intervention, safety, integrity, maintenance and/or abandonment.
  • tank (13) or separator (12) accessible with, e.g., cables, tools, cameras or other apparatuses usable within a subterranean environment for well construction, production, intervention, safety, integrity, maintenance and/or abandonment.
  • the wells may be completed by placing fluid communication conduits for injection and/or production (182) with a lower end tail pipe and mandrel (169), engagable to a PBR (168, 168C), wherein the upper end of the conduit (182) may be connected to a hanger in a conduit hanger spool of a wellhead when a central access well bore (59Y7) is not used, or engaged to the lower end of a second chamber junction manifold crossover (21Y) to transition from axially autonomous conduits (34) to concentric conduits (35) and a central access well bore (59Y7), wherein plugs (25A) may be placed in an axial autonomous chamber junction exit conduits to divert fluid flow into elongate segregated annulus passageways feeding into concentric passageways.
  • plugs (25A) may be placed in an axial autonomous chamber junction exit conduits to divert fluid flow into elongate segregated annulus passageways feeding into concentric passageways.
  • a valve manifold crossover (20Z) may then be placed in the well bore (59Y7) and engaged to the chamber junction crossover (21Y) to control the concentric passageways with subterranean safety valves (24, 24A, 24B, 24C), wherein any of the flow streams may be stopped without affecting the remaining flow streams.
  • Plugs (25A) can be used to crossover flow within the manifold (20Z), which may be removed to access plugs (25A) in the chamber junction crossover (21Y), which may be removed to access the autonomous well bore's (59Y2, 59Y4, 59Y6) lower ends.
  • Control lines (200) for each of the valves may be passed through apparatuses using control line passageways (167) and annuli and/or a plurality of control lines may be bundled into an umbilical (200B), which can be used to extend the surface for monitoring and control of the safety valves and/or other subterranean equipment needing a control lines umbilical.
  • Control lines and umbilical bundles of cables and conduits may also terminate in subterranean wet connections that are engaged by placing a cable connection, e.g. by pumping against a piston on its lower end, from surface to the wet connector.
  • a separator inlet manifold crossover (20Y) may be placed axially above and engaged to the safety valve control manifold crossover (20Z) in the central access well bore (59Y7), wherein flow diverting apparatuses (e.g. 25A of Figure 119C or 25C of Figure 199C) may be used to divert flow to a separator inlet (26) and diverter (29) usable for erosional protection of the ported (240) central well bore (59Y7) access to the tank (13), fluid separator (11) and/or heat exchanger (12) annulus.
  • the ports (240) may be covered with, e.g., a wear bushing, or left open if access to the tank is desired to store, e.g., drilling fluids.
  • the lower end of the tank (13) may be fluidly accessed with, e.g., a ported subassembly (241) having nipple profiles (175) engagable with a straddle (e.g. 25E of Figure 119E) that may be removed for access and placed for closure of the fluid communicating ports.
  • the lower end of the tank (13), separator (11) or heat exchanger (12) may be cleaned, e.g., by circulating across two ported assemblies (241) or by taking suction on the ported assembly (241) to remove heavier water and any solids which have settled to the bottom of the tank via gravity.
  • Ported assemblies (241) may be added along the axis of well bores for various reasons, including, e.g., as an hydrocarbon outlet (98 of Figure 16 ), wherein valves may be inserted during installation with a drilling rig (51A of Figure 1 , 51C of Figure 4 ), or subsequently using a cable or wireline rig (51D of Figure 3 ) to act as vertical fluid separator (11) level control valves (100, 101), wherein wet connections and/or permanently installed cables are usable with computer controlled processing (108 of Figure 17 ).
  • a plurality of wells may be placed from a central access within a single main bore, however it should be understood that this example is one of various ways to construct a subterranean well, and the application of a LDHP conduit system (1) using manifold crossovers and chamber junctions may be practiced other than as specifically described herein.
  • a plurality of wells, manifold junctions and chamber junctions are not a required feature of the present invention, as described in Figure 5 .
  • Substantially parallel circumferentially and axially autonomous well bores may be passed through the single main bore of a LDHP conduit system (1) to engage separate flow control devices, such as BOPs and valves trees, or separate bore apparatuses such as plurality of bore valve trees so as to fluidly communicate producible and injectable fluids to and from the subterranean strata.
  • separate flow control devices such as BOPs and valves trees
  • separate bore apparatuses such as plurality of bore valve trees
  • a lower end chamber junction is not necessarily required for forming a plurality of wells through the single main bore of a LDHP conduit system (1), since the lower end may be cemented closed or left open to use the fracture gradient of the surrounding strata for pressure relief of the annulus about the plurality of wells.
  • FIG. 106 and 107 depict upper and lower isometric views, respectively, of an axially concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47A) of a LDHP conduit system (1) embodiment (1AC), which is shown as a dashed line, to illustrate that a smooth transition may be used to reduce the erosional friction simultaneous fluid flow stream velocities, wherein the transition (47) may not necessarily be a manifold crossover (20) or chamber junction (21) embodiment (21AB), since the crossover of flow may not be desirable or controllable and access to all lower end axially autonomous conduits may not be possible or desired. Additionally, while the lower end conduits are axially autonomous, it may not be necessary to make them circumferentially autonomous and hence may share an outer circumference.
  • Figure 108 depicts a plan view with dashed lines showing hidden surfaces of a LDHP conduit system (1) embodiment (IAD).
  • the Figure illustrates a concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47B) alternative to (47C) of Figures 109-110 .
  • the chamber junction (21) crossover embodiment (21AA) illustrates how a transition may also be a chamber junction (21, 21AA), wherein a bore selector (32) and diverter, e.g.
  • FIG. 109 and 110 isometric and elevation views, respectively, depict a concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47C) similar to the sized transition (47B) of Figure 108 , with a LDHP conduit system (1) embodiment (1AE) shown as a dashed line.
  • the depicted arrangement may be usable in instances where the erosional effects of flow velocities are less significant than the cost of construction, wherein a simple upper end right angle design is used to transition from axially autonomous (34) to axially concentric (35) conduits.
  • a bore selector extension receptacle (242) similar to that of Figure 108 , is usable to orient a bore selector (32) or diverter (e.g. 25B of Figure 119B ) usable to divert fluids and apparatus to and from lower end autonomous conduits (34).
  • Figures 111 and 112 show elevation and plan views, respectively, illustrating a concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47D) of a side-pocket whipstock (48) embodiment (48A) for a LDHP conduit system (1) embodiment (1AF), which is shown as a dashed line.
  • Two 40.6 cm (16") outside diameter conduits are offset by 10.2 cm (4") to provide a bore with vertical access similar to any conventional well, wherein the amalgamation of both bores is placeable within a 50.8 cm (20") ID to form a side-pocket arrangement (48A) for urging one or more lateral bores (244) from a through bore (245) with a kick-over tool from a conduit (246).
  • the entire assembly may be placed in a bore and cemented in place, after which a vertical and one or more lateral bores may be drilled and lined.
  • Figures 113, 114, 115, 116, 117 and 118 the Figures illustrate a plan view with line AM-AM, an elevation cross-section along line AM-AM of Figure 113 with break lines showing sections removed, an isometric projection of Figure 114 with detail lines AN and AO, a magnified detail view within line AN of Figure 115 , a magnified detail view within line AO of Figure 115 , and an exploded view associated with the components of Figures 113-117 , respectively, which depict a chamber junction (21) side-pocket whipstock conduit (48) assembly embodiment (48B).
  • the depicted embodiment (48B) includes concentric and axially autonomous snap-together connector (49) embodiments (49H, 491) within a LDHP conduit system (1) embodiment (1AG), which is shown as a dashed line, wherein the chamber junction (21) may be used as a side-pocket whipstock (33) embodiment (33C).
  • the conduit body (48) assembly has upper (49H) and lower (491) end box snap connector (251) assemblies comprising axially autonomous (34) conduits with a side pocket bore (199), formed between the ends on the inside diameter of a chamber junction conduit.
  • the bore (199) can be usable for drilling a strata passage and placing a protective metal lining within the strata passageway to form an axially autonomous (34) bore (199), extending axially downward and laterally outward from a lower end whipstock (e.g. 46 of Figure 121 ) by exiting the outside diameter the conduit assembly (48) at an axial inclination.
  • the axis of the autonomous bore (199) is axially and laterally offset from the through passage (198) and can be accessed via a kick-over tool (e.g. 33K of Figure 119 ).
  • Supporting conduits (246) can form part of the conduit assembly (48B), wherein the supporting conduits can be usable to, e.g., improve fluid circulation, cementing operations, provide a gas lift conduit and/or to monitor a liner annulus.
  • a conduit housing (247) encloses the chamber junction (21J), adapted for kick-over diversion to the side pocket whipstock bore (199), wherein an upper snap connector embodiment is shown having has three PBR receptacles for engagement to a corresponding chamber junction or supporting conduits and associated mandrel seal stacks of a corresponding axially autonomous conduit assembly.
  • the lower end four seal stack mandrels (249, 250) and adapted chamber junction (248, 21J) are engagable to the conduit housing (247) with a bracket (200J) and associated lower end, which is engagable to another axially autonomous conduit whipstock assembly (e.g. 48C of Figures 120-125 ).
  • Figures 119, 119A, 119B, 119C, 119D and 119E show a top down isometric view of a diverting apparatus (25) kick-over tool (33K) embodiment (33K1), a top down isometric view of a diverting apparatus (25) prior art plug (25A), a bottom up isometric view of a diverting apparatus (25) embodiment (25B) comprising a bore selector (32) of the present inventor, a top down isometric view of a diverting apparatus (25) simultaneous flow stream turbine (25C) of the present inventor, a top down isometric view of a diverting apparatus (25) embodiment (25D) comprising a bore selector (32) of the present inventor and a top down isometric view of an prior art diverting apparatus (25) profile snap-in sleeve or straddle (25E), respectively, which illustrate various diverting apparatuses usable with embodiments of the present invention.
  • the kick-over tool (33K) embodiment (33K1 of Figure 119 ) may be used for placing or retrieving well equipment via a through passage (198 of Figures 113 ) of a conduit (e.g. 248 of Figures 113-125 ) adjacent to said side pocket whipstock lateral bore (199), wherein the kick-over tool may have an elongate body (197) with an arm (195) movable with said body and/or axially rotatable from a pivot point (196), e.g. if a second kick-over arm (195 of Figure 130-131 ) is attached to the first pivot arm.
  • a kick over tool's running position may comprise, e.g., engagement to a running tool that is released after setting rotatable packer slips (252) using a drag block spring (254) to place the kick-over tool in its equipment deflection, placement and retrieval position.
  • a movable spring (253) piston or other cushioning device may be used to facilitate a tool and/or drill string deflection off of the movable arm (195) and/or engagement/disengagement spring (253).
  • a spline (255) may be used with an overshot retrieval tool to release the packer slips (252) and retrieve the kick-over tool, wherein any means of placement and retrieval of a tool that can be used to deflect fluids and/or tools into the side pocket bore (199) using any mechanism which acts as an arm to cause said deflection is usable, whereby, e.g., any casing packer which may be set and retrieved and be used as a deflecting apparatus without significant damage to tools or the well.
  • any tool acting as an arm to place or retrieve equipment to and from the lateral bore (199) of said side pocket whipstock (48B) by placing and retrieving said kick-over tool in a first position for running and retrieval and a second position to engage and deflect said equipment approximately into said lateral bore may be used to facilitate access, since the chamber junction (21J) may control the orientations of equipment entering the area of the side pocket whipstock.
  • the deflection tool 25B of Figure 119B
  • the deflection tool may be mounted onto a packer slip arrangement (252 of Figure 119 ) and oriented to cause its whipstock (46) to act as a pivot (196) and deflecting arm (195) when placed in the chamber junction.
  • the diverting apparatuses (25) shown as a plug (25A of Figure 119A ) and manifold crossover turbine (25C of Figure 119C ) have dog mandrels (256) engagable with nipple profiles (175) to block or divert primarily fluid flow, wherein the plug arrangement (25A) could be used as a kick-over tool when, e.g., a whipstock (46) adaptation acting as a pivot arm is placed upon the upper end arm (195 of Figure 119A ) of the plug (25A).
  • the manifold crossover turbine (25C) with upper end running mandrel (257) is usable to drive and/or assist one flow stream with the flowing energy of another, wherein when placed within a receptacle profile of a manifold crossover (e.g. 20W of Figure 62 , 20AA of Figure 65 and 20Y of Figures 66-68 ), at the point of crossover between annulus and inner bore, one flow stream's energy may drive one turbine (258), which through a common axis, drives the opposite turbine (259) to energize the fluid flow associated with that turbine, or vice versa.
  • a manifold crossover e.g. 20W of Figure 62 , 20AA of Figure 65 and 20Y of Figures 66-68
  • Such a turbine may be used with, e.g., production moving through a subterranean separator (11) where the expansion of a gas entrained fluid passes the turbine into the tank (13) it may be used to lift dense fluid production or drive water injection and/or disposal.
  • the straddle (25E of Figure 119E), or any other similar device deployable and retrievable with a cable rig, e.g. 25D of Figure 3 may be used to close open ports adjacent to engagable nipple profiles (175) in subterranean conduit, e.g. a separator inlet (26 of Figures 62-68 ), or crossover ports, wherein operation of the port may comprise installing and removing such sealable straddles which close side orifices but allow fluid and/or tool passage through an interior passageway and which may be snapped into and removed from downhole nipple profiles.
  • Figures 120 and 121 show a plan view with line AP-AP and a cross section elevation view along line AP-AP with break-lines representing removed portions of a side-pocket (48) whip-stock (46) embodiment (48C) with axially autonomous snap-together connector (49) embodiments (491, 49J) of a LDHP conduit system (1) embodiment (1AH), shown as a dashed line.
  • the Figures illustrate a side pocket (33) embodiment (33D) comprising a conduit body (48) with upper (491) and lower (49J) end connectors for an autonomous (34) bore (199) side pocket usable for urging a strata passage and hanging a protective metal lining, e.g.
  • a liner hanger (167), axially downward and laterally outward from a lower end whipstock (46) exiting the outside diameter conduit body (48), wherein a kick-over tool may be placed in the through passage (198) to deflect passage to the lateral bore (199).
  • the upper end connector (491) of the conduit assembly (48C) may be used to engage kick-over tools, e.g. (33K1) of Figure 119 or a chamber junction arrangement (e.g. 48B o Figures 113-118 ).
  • Figures 122, 123, 124 and 125 depict a plan view with AQ-AQ, an elevation cross-section along line AQ-AQ of Figure 122 with break lines representing removed sections and detail lines AR and AS, a magnified detail view within line AR of Figure 123 and a magnified detail view within line AS of Figure 123 , depicting a side-pocket (48) whip-stock (46) embodiment (48D), associated with the engagement of embodiments (48B, 48C) of Figures 113-121 , with axially autonomous snap-together connector (49) embodiments (49H, 491, 49J) of a LDHP conduit system (1) embodiment (IAI), shown as a dashed line.
  • a side-pocket (48) whip-stock (46) embodiment (48D) associated with the engagement of embodiments (48B, 48C) of Figures 113-121 , with axially autonomous snap-together connector (49) embodiments (49H, 491, 49J) of a LDHP conduit system (1) embodiment (IAI), shown as a
  • a diverting (25) kick-over tool (33K) embodiment (33K1) may be installed in a through passageway (198) in a first running position (33K1A) before engaging packer slips (197) and a second position (33K1B) for equipment diversion through the side pocket bore (199) use the arm (195) for placing and retrieving the apparatus or fluids after engaging the slips.
  • FIGS 126 and 127 depict a plan view with line AT-AT and an elevation cross section view along line AT-AT with break lines representing removed portions a side-pocket conduit (48) whip-stock (46) embodiment (48E) of a LDHP conduit system (1) embodiment (1AJ), shown as a dashed line.
  • a side pocket (33) embodiment (33E) within a conduit body (48) having upper and lower ends engagable with any form of subterranean connector may be accessed from the through bore (198), wherein an axially autonomous (34) bore (199) side pocket is formed on the inside diameter, between the upper and lower ends thereof.
  • the lateral bore (199) may be used for urging a subterranean strata passage and hanging a protective metal lining when a kick-over tool is used to access said autonomous bore (199) from said through passageway (198), as shown in Figures 128-132 .
  • Additional supporting axially autonomous conduits may also be placed secured with a bracket (263).
  • Figures 128 and 129 depict a plan view with line AU-AU and an elevation cross section view along line AU-AU with break lines representing removed portions, which shows a side-pocket conduit (48) whip-stock (46) embodiment (48F), and a side pocket (33) embodiment (33F) and kick-over tool (33K) embodiment (33K2), illustrating the kick-over tool in the running position (33K2A) within a LDHP conduit system (1) embodiment (1AK), shown as a dashed line.
  • the kick-over tool (33K) embodiment (33F) is usable for placing or retrieving well equipment via a through passage (198) of a conduit adjacent to a side pocket whipstock lateral bore (199), wherein said kick-over tool may comprise an elongate body (197) with an arm (195) movable with said body and axially rotatable from a pivot point (196) using, e.g., a j-slot (260) arrangement with said elongate body, between a first, kick-over tool running and retrieving position (33K2A), and a second position (33K2B of Figures 130-132 ) for the arm to place or retrieve equipment to and from the lateral bore (199) of said side pocket (33) whipstock conduit (48).
  • said kick-over tool may comprise an elongate body (197) with an arm (195) movable with said body and axially rotatable from a pivot point (196) using, e.g., a j-slot (260) arrangement with said elongate
  • the tool (33K2) may be placed and retrieved with any form of running tool to place the elongate body (197) approximately adjacent to the lateral bore (199) so as to divert well equipment, e.g. drill strings, casing liners, perforating guns, packers or any other suitable downhole apparatus, to and from said lateral bore.
  • well equipment e.g. drill strings, casing liners, perforating guns, packers or any other suitable downhole apparatus
  • Figures 130, 131 and 132 depict a plan view with line AV-AV, an elevation cross section along line AV-AV of Figure 130 with detail line AW and break lines representing remove sections and a magnified detail view within line AW of Figure 132 , depicting a side-pocket (33) whip-stock (46) conduit (48) embodiment (48G) with a kick-over tool (33K) embodiment (33K2) in a diverting position (33K2B) within a LDHP conduit system (1) embodiment (1AL), shown as a dashed line.
  • piston packer (261) and rod (262) and/or springs and weight set mechanisms may be used to extend the arm (195) of the kick-over tool (33K2) to the diverting position (33K2B) and/or retract it to a running and retrieving position (33K2A).
  • the tool (33K2) may be engaged to the through bore (198) with a kidney shaped profile orienting the arm and providing an axial position for setting a packer with slips to anchor the kick-over tool, after which the force of separating from the anchored tool may be used with, e.g., a piston (261) and rod (262) moved axially upward to operate the j-slot (260) and pivot point (196) of the diverting arm (195).
  • the piston and rod may again be operated downward for retraction of the arm to the running position, after which the tool may be disengaged from the pass through bore (198) and retrieved to surface.
  • Any means of operating a kick-over tool e.g. an adaptation of a kick-over tool used for gas lift valves modified for the larger bores may be used.
  • the length of the pass through bore (198) of conduit (48) between side pockets (33) may be significant, for example it may be measured in hundreds of feet or metres so as to allow a drill string comprising, e.g., a pendulum assembly, rotary steerable, bent housing and motor operating drill collars, stabilizers, bits, bi-centre bits, hole openers and/or other boring devices used for directionally drilling at inclinations of, e.g., 1-3 degrees per 30 metres or 100 feet when exiting the side pocket (33), which may be of a similar length to allow the installation of a liner hanger.
  • a drill string comprising, e.g., a pendulum assembly, rotary steerable, bent housing and motor operating drill collars, stabilizers, bits, bi-centre bits, hole openers and/or other boring devices used for directionally drilling at inclinations of, e.g., 1-3 degrees per 30 metres or 100 feet when exiting the side pocket (33), which may be of a similar length to allow the installation of
  • a side-pocket (33) whipstock conduit (48) and kick-over tool of the present invention is generally not applicable to conventional well design which lack sufficient space and/or pressure bearing capacity, hence a LDHP conduit system (1) may effectively be used to operate a side pocket and kick-tool to create level 6 multilaterals, wherein a cased, cemented and pressure tight junction is present, in larger hole diameters than are conventionally possible using conventional apparatuses designed for single bore liners.
  • Various prior and conventional multilateral tool may be adapted to use with the present invention, to provide the same benefits of using larger hole sizes with higher pressure ratings.
  • the present invention is neither obvious to practitioners who have used substantially the same well bore size since at least 200 BC, as evidenced by industry conduit standard 5CT of the American Petroleum Institute (API) regarding the qualification of well conduits up to 50.8 cm (20"), nor is it necessarily the lowest cost option for use in various areas where surface strata is particularly difficult to bore, even with our current level of technology; however, a very serious need exists to access unconventional and extremely difficult subterranean deposits, wherein providing subterranean processing in remote and subsea locations reduces the required infrastructure and reduces the number of penetrations through ground water systems and/or moderates the use of surface areas in environmentally sensitive areas, forests, farmlands and/or populated areas where drilling and well production have significant negative impact.
  • API American Petroleum Institute
  • the large diameter high pressure conduit system (1) described herein may be used to meet such needs in a more cost and carbon footprint conscious manner, by reducing surface impact to vegetation, minimising fuels and resources used to construct a plurality of wells and providing a design for more economically producing and maximising recover of cleaner burning fuels, such as gas, wherein present modern advances in subterranean technologies may be used to control producible and/or injectable subterranean single or simultaneous fluid flow streams of varying velocities to and/or from one or more wells through a single main bore with pressure bearing capacities greater than are presently practiced using larger diameter conduits to access conventional and unconventional subterranean deposits with a design that is usable with virtually any off-the-shelf field proven technology and which may be standardized to further reduce costs and environmental impact.

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Claims (19)

  1. Bohrlochleitungssystem (1), umfassend:
    eine erste (2) umlaufend elastische äußere Leitungswand,
    wenigstens eine zweite (3) umlaufend elastische innere Leitungswand, die sich innerhalb der ersten umlaufend elastischen äußeren Leitungswand befindet, um eine ringförmige Öffnung zwischen der ersten umlaufend elastischen äußeren Leitungswand und der wenigstens einen zweiten umlaufend elastischen inneren Leitungswand zu definieren,
    eine Vielzahl von radialen Lastflächen (5, 6, 41, 42, 49, 123), die sich über die ringförmige Öffnung und radial zwischen wenigstens zweien der Leitungswände erstrecken, um konzentrisch an wenigstens einer anderen der Leitungswände anzuliegen, um wenigstens zwei elastische mit Ringspannung aneinander angrenzend verbundene Rohrkörper (4) mit wenigstens einem konzentrischen Ringraum (7) zwischen den wenigstens zwei elastischen mit Ringspannung aneinander angrenzend verbundenen Rohrkörpern und der Vielzahl von radialen Lastflächen zu bilden,
    wobei ein oder mehrere Durchgänge durch unterirdische Schichten gebildet sind, indem ein innerer Rohrkörper, der wenigstens eine zweite umlaufend elastische innere Leitungswand umfasst, in einen äußeren Rohrkörper, der die erste umlaufend elastische äußere Leitungswand umfasst, eingesetzt wird, wobei der innere Rohrkörper einen Außendurchmesser umfasst, der größer als ein Innendurchmesser des äußeren Rohrkörpers ist, und wobei der innere Rohrkörper unter Verwendung einer umlaufend elastischen Dehnung des äußeren Rohrkörpers und einer umlaufend elastischen Komprimierung des inneren Rohrkörpers als Ergebnis einer zwischen denselben ausgeübten Ringspannungskraft unter wenigstens einer Bohrlochkopfanordnung (10) in den äußeren Rohrkörper eingesetzt wird, und
    wobei ein Lösen der Ringspannungskraft nach dem Einsetzen die umlaufend elastische Dehnung und die umlaufend elastische Komprimierung löst, um die Vielzahl von radialen Lastflächen des äußeren Rohrkörpers an den inneren Rohrkörper anzulegen, um aneinander angrenzend verbundene Rohrkörper zu bilden und um zu bewirken, dass ein elastischer Ringspannungswiderstand (8) zwischen den aneinander angrenzend verbundenen Rohrkörpern konzentrisch geteilt wird, um eine größere effektive Wanddicke (9) zu bilden, die in der Lage ist, höhere Drücke zu enthalten, als die Leitungswände ansonsten ohne das konzentrische Teilen des elastischen Ringspannungswiderstands aushalten könnten.
  2. Bohrlochleitungssystem nach Anspruch 1, wobei die radialen Lastflächen einen Abschnitt wenigstens eines der Rohrkörper (4), einen Abschnitt eines in Bezug auf den wenigstens einen der Rohrkörper zwischenliegenden unabhängigen Lagers oder eine Kombination aus denselben umfassen.
  3. Bohrlochleitungssystem nach Anspruch 1 oder Anspruch 2, wobei die radialen Lastflächen einen plastischen Verformungsabschnitt oder einen elastisch dehnbaren Abschnitt umfassen, der so nutzbar ist, dass er das Anliegen der Vielzahl der radialen Lastflächen und das konzentrische Teilen des elastischen Ringspannungswiderstands (8) zwischen den aneinander angrenzend verbundenen Rohrkörpern bereitstellt.
  4. Bohrlochleitungssystem nach einem der vorhergehenden Ansprüche, wobei die Ringspannungskraft Gravitationskräfte, Schlagkräfte, mechanische Kräfte (38), Strömungskräfte oder pneumatische Kräfte (39) oder eine Kombination aus denselben umfasst.
  5. Bohrlochleitungssystem nach einem der vorhergehenden Ansprüche, ferner umfassend eine Bohrlochkopfanordnung (10) aus wenigstens einer Unterbaugruppe einer fluidisch verbindenden Leitungshängerspule (14), die mit Komponenten, die an einer ersten (17) Leitungskopfunterbaugruppe und wenigstens einer zweiten (18) Leitungskopfunterbaugruppe befestigbar (15) und versiegelbar (16) sind, in Eingriff gebracht werden können, wobei die erste (17) und die wenigstens eine zweite (18) Leitungskopfunterbaugruppe mit einem oberen Ende der ersten (2) umlaufend elastischen äußeren Leitungswand und der wenigstens einen zweiten (3) umlaufend elastischen inneren Leitungswand verbunden und an demselben befestigt sind, um die Bohrlochkopfanordnung zu bilden.
  6. Bohrlochleitungssystem nach einem der vorhergehenden Ansprüche, wobei einzelne (41) oder doppelte (42) Schneidringverbindungen verwendet werden, um wenigstens zwei Leitungswände eingreifend an der Bohrlochkopfanordnung zu befestigen und zu versiegeln.
  7. Bohrlochleitungssystem nach einem der vorhergehenden Ansprüche, ferner umfassend wenigstens eine Bohranordnung (1B, 1C, 1G, 1H), die mit der Bohrlochkopfanordnung in Eingriff gebracht werden kann, um den einen oder die mehreren Durchgänge durch die unterirdischen Schichten zu treiben.
  8. Bohrlochleitungssystem nach einem der vorhergehenden Ansprüche, wobei eine Vielzahl von im Wesentlichen konzentrischen Leitungen (35), axial unabhängigen Leitungen (34) oder Kombinationen aus denselben (47) zusammengesetzte Verbindungen bilden, die durch die Rohrkörper anordenbar sind, um den einen oder die mehreren Durchgänge durch die unterirdischen Schichten zu bilden.
  9. Bohrlochleitungssystem nach Anspruch 8, wobei die zusammengesetzten Verbindungen eine Vielzahl von Schnappverbindern (49) für die parallelen axial unabhängigen gleichzeitig in Eingriff bringbaren Leitungen (34) umfassen, wobei die Schnappverbinder (49) elastisch komprimierbare Innenumfänge und elastisch dehnbare Außenumfänge (4A) umfassen, um im Wesentlichen konzentrische Leitungen (35) oder axial unabhängige (34) Leitungen zu verbinden.
  10. Bohrlochleitungssystem nach Anspruch 8, wobei ein oder mehrere Ventile (24) oder Umlenkvorrichtungen (25, 32, 33K) selektiv so angeordnet sind, dass sie eine Übermittlung durch den einen oder die mehreren Durchgänge durch die unterirdischen Schichten steuern.
  11. Bohrlochleitungssystem nach Anspruch 10, wobei die gesteuerte Übermittlung das Verwenden eines Computers (102, 108) umfasst, um die Ventile zu betätigen oder um die Umlenkvorrichtungen (25, 32, 33K) zu betätigen, und zwar durch Verwendung von beobachteten Drücken, Temperaturen und Strömungsgeschwindigkeiten von Flüssigkeiten, um Flüssigkeiten durch den einen oder die mehreren Durchgänge durch die unterirdischen Schichten zu übermitteln.
  12. Bohrlochleitungssystem nach Anspruch 8, ferner umfassend eine oder mehrere unabhängige Bohrungen, die mit einer Vielfachweiche (20), einer Kammerverbindung (21), einem Seitentaschenablenkkeil (48) oder einer Kombination aus denselben gebildet sind.
  13. Bohrlochleitungssystem nach Anspruch 12, wobei der Seitentaschenablenkkeil (48) eine Seitentasche (33) mit einer axial unabhängigen (34) Bohrung (199) umfasst, die sich zu einem Ablenkkeil (46) an einem unteren Ende erstreckt, der von dem Durchgang (198) seitlich versetzt ist.
  14. Bohrlochleitungssystem nach Anspruch 12 oder Anspruch 13, wobei wenigstens ein Bohrungsauswahlwerkzeug (32), ein Kick-Over-Werkzeug (33K) oder Kombinationen aus denselben selektiv durch den einen oder die mehreren Durchgänge angeordnet und zu diesen ausgerichtet sind, um Zugang zu der einen oder den mehreren unabhängigen Bohrungen zu erhalten.
  15. Bohrlochleitungssystem nach Anspruch 14, wobei das Kick-Over-Werkzeug (33K) einen längserstreckten Körper (197) mit einem beweglichen Arm (195), einen axial rotierbaren Drehpunkt (196) oder Kombinationen aus denselben umfasst, die dazu dienen, Bohrlochausrüstung durch die seitliche Seitentaschenablenkkeilbohrung (199) über den Durchgang (198) zu platzieren oder herauszuholen.
  16. Bohrlochleitungssystem nach einem der vorhergehenden Ansprüche, wobei ein unterirdischer Flüssigkeitsverarbeitungsbehälter (13) innerhalb der Rohrkörper zwischen der wenigstens einen Bohrlochkopfanordnung und dem unteren Ende der Rohrkörper gebildet ist und wobei der Flüssigkeitsverarbeitungsbehälter wenigstens einen des einen oder der mehreren Durchgänge durch die unterirdischen Schichten umgibt und mit diesen fluidisch verbunden ist.
  17. Bohrlochleitungssystem nach Anspruch 16, wobei der unterirdische Flüssigkeitsverarbeitungsbehälter (13) dazu dient, eine unterirdische Trenneinrichtung (11) zu bilden, die verbindende, im Wesentlichen konzentrische oder axial unabhängige Leitungswände und Durchgänge umfasst, die Einlässe (26), Kamine (27), Fallleitungen (28), Umlenker (29), Abstandshalter (30), Tropfenabscheider (31) oder Kombinationen aus denselben bilden, um Flüssigkeiten während der Flüssigkeitsverarbeitung abzuscheiden.
  18. Bohrlochleitungssystem nach Anspruch 16, wobei der unterirdische Flüssigkeitsverarbeitungsbehälter (13) einen Wärmetauscher (12) bildet, der verbindende, im Wesentlichen konzentrische oder axial unabhängige Leitungswände nutzt, um Wärme zwischen innerhalb der verbindenden, im Wesentlichen konzentrischen oder axial unabhängigen Leitungswände befindlicher Flüssigkeit und um die verbindenden, im Wesentlichen konzentrischen oder axial unabhängigen Leitungswände herum befindlicher Flüssigkeit in dem unterirdischen Flüssigkeitsverarbeitungsbehälter auszutauschen, um die unterirdische Flüssigkeitsverarbeitung weiter bereitzustellen.
  19. Verfahren zur Verwendung eines Bohrlochleitungssystems (1), wobei das Verfahren die folgenden Schritte umfasst:
    Bereitstellen einer umlaufend elastischen äußeren Leitungswand (2) und wenigstens einer zweiten umlaufend elastischen inneren Leitungswand (3) mit einer Vielzahl von radialen Lastflächen (5, 6, 41, 42, 49, 123), die sich über wenigstens einen Abschnitt von wenigstens zweien der Leitungswände radial zwischen denselben erstrecken, um konzentrisch an wenigstens einer der Leitungswände anzuliegen, um wenigstens zwei elastische mit Ringspannung aneinander angrenzend verbundene Rohrkörper (4) zu bilden, die einen oder mehrere Durchgänge des Bohrlochs mit wenigstens einem konzentrischen Ringraum (7) zwischen den aneinander angrenzend verbundenen Rohrkörpern und der Vielzahl von radialen Lastflächen bilden,
    Bilden des einen oder der mehreren Durchgänge durch unterirdische Schichten durch Einsetzen eines inneren Rohrkörpers, der wenigstens eine zweite umlaufend elastische innere Leitungswand umfasst, in einen äußeren Rohrkörper, der die umlaufend elastische äußere Leitungswand umfasst,
    wobei der innere Rohrkörper einen Außendurchmesser umfasst, der größer als ein Innendurchmesser des äußeren Rohrkörpers ist, und wobei der innere Rohrkörper unter Verwendung einer umlaufend elastischen Dehnung des äußeren Rohrkörpers und einer umlaufend elastischen Komprimierung des inneren Rohrkörpers als Ergebnis einer zwischen denselben ausgeübten Ringspannungskraft unter wenigstens einer Bohrlochkopfanordnung (10) in den äußeren Rohrkörper eingesetzt wird, und
    Lösen der Ringspannungskraft nach dem Einsetzen, um die umlaufend elastische Dehnung und die umlaufend elastische Komprimierung zu lösen und die Vielzahl von radialen Lastflächen des äußeren Rohrkörpers an den inneren Rohrkörper anzulegen, um aneinander angrenzend verbundene Rohrkörper zu bilden und um zu bewirken, dass ein elastischer Ringspannungswiderstand (8) zwischen aneinander angrenzend verbundenen Rohrkörpern konzentrisch geteilt wird, um eine größere effektive Wanddicke (9) zu bilden, die in der Lage ist, höhere Drücke zu enthalten, als die Leitungswände ansonsten ohne das konzentrische Teilen des elastischen Ringspannungswiderstands aushalten könnten.
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CN104271999A (zh) 2015-01-07
EP2820338A4 (de) 2016-08-03
EP2820338A1 (de) 2015-01-07
WO2013176705A1 (en) 2013-11-28
CN104271999B (zh) 2018-02-02

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