GB2514075A

GB2514075A - High pressure large bore well conduit system

Info

Publication number: GB2514075A
Application number: GB1203649.7A
Authority: GB
Inventors: Bruce Arnold Tunget
Original assignee: Individual
Current assignee: Individual
Priority date: 2011-03-01
Filing date: 2012-03-01
Publication date: 2014-11-19
Anticipated expiration: 2032-03-01
Also published as: GB201111482D0; GB2484166B; GB2514075B; GB201121741D0; GB201121742D0; GB2487274A; GB2486591B; GB2487274B; GB201203649D0; GB2486591A; GB2484166A

Abstract

Apparatus and method comprising a well conduit system 1 comprising inner 3 and outer 2 concentric conduits, the conduits defining an annular space 7 through which radial loading surfaces or supports 6 extend. The supports extend from one of the conduit and abut against the other. The supports are longer than the annular distance between the conduits such that the conduits are in a pre-stressed state when concentrically arranged. The arrangement allows hoop stress resistances to be shared between the two conduits to form a greater effective wall thickness and therefore increasing the systems pressure bearing capacity.

Description

HIGH PRESSURE LARGE BORE WELL CONDUIT SYSTEM

[0001] The present application claims priority to Patent Cooperation Treaty Application Number US201 1/000377, entitled "Manifold String For Selectively Controlling Flowing Fluid Streams of Varying Velocities In Wells From A Single Main Bore," filed March 1, 2011; United Kingdom Patent Application having Number GBI 104278.5, of the same title, filed 15 March, 2011. PCT Application Number US2O1 1/000372, entitled "Pressure Controlled Well Construction and Operation Systems and Methods Usable for Hydrocarbon Operations, Storage And Solution Mining," filed March 1, 2011; and United Kingdom Patent Application having Number GB 1104280.1, of the same title, filed 15 March, 2011, each of which is incorporated herein in its entirety by reference.

FIELD

[0002] The present invention relates, generally, to the field of constructing and operating subterranean wefls exploiting subterranean deposits. for example (e.g.) those associated with waste fluid disposal of contaminated water and carbon dioxide (C02) sequester, salt production and salt cavern storage, geothermal steam and hydrocarbons, wherein the efficiency of a well may be improved with the use of a larger diameter higher pressure well conduit system to provide one or more wells through a single large diameter high pressure main bore with otherwise conventionally practiced method and apparatus usable within said single main bore, and wherein the passageway spaces within said large diameters provide improved integrity and opportunity for beneficial placement of subterranean apparatuses, e.g. subterranean apparatuses, separators heat exchangers, side pocket whipstocks for side tracking wells and other apparatuses for extracting and processing of injectable and producible fluids from said one or more wells a more efficient and/or environmenta'ly conscious manner than is currendy practiced.

[0003] The present invention uses the natural flexure of larger diameter conduit structures, generally greater than 7" in diameter, with restraining hoop stress resistances, in other words the resistance to the stresses of expansion or burst andlor compression or collapse of the circumference of a circular shaped (hoop) structure, wherein the present system of well conduits may be formed with simple low cost radial loading surface abutments between conduits that share adjoining conduit hoop stress resistances to form higher pressure structures than are possible by using the same conduit sizes in isolation, which is the conventional practice.

[0004] The present well conduit system with large diameter higher pressure conduit containing fluid communication conduits represents a significant improvement on conventional well designs and inventions of the present inventor's United Kingdom Patent CB2465478B entitled "Apparatus And Methods For Operating A Plurality Of Wells Through A Single Bore," granted 9 March 2011, wherein the embodiments of United Kingdom Patent GB2471760B entitled "Apparatus And Methods For Subterranean Downhole Cutting Displacement. And Sealing Operations Using Cable Conveyance," granted 1 February 2012, may be used within the present invention for maintenance, boring and/or abandonment, wherein both patents are induded in their entirety by reference. Improvements to UK Patent GB2465478B, provided by the present invention, generally comprise the addition of a larger diameter higher pressure conduit and individual annulus access, well integrity and autonomous flow features to providing a plurality of parallels wells through the larger diameters that also comprise p'urality of wells through a single main bore, wherein the addition of vanous processing apparatuses may also be included and maintained via the teachings of UK Patent GB2471760B and wherein present invention embodiments of a side-tracking whipstock side pockets for drilling laterals from a well bore are.

e.g., usable by UK Patent GB247 I 760B, or by more conventional drill string means.

The present invention also incorporates the teachings of UK Patent Application CB1021787.5, entitled "Managed Pressure Conduit Systems And Methods For Boring And Placing Conduits Within The SubtelTanean Strata," filed 16 December 2009, included herein in its entirety by reference.

[0005] The present invention also makes significant improvements upon the teachings of: Morgan and Sinclair in US Patent Application Number US 2011/0068574 Al, published 24 March 2011 entitled "Pipe Connector Device;" those taught by Gallagher and Lumsden in US Patent 5,954,374 entitled "Pipe Connectors," granted 21 September 1999; those taught by Bilderbeek and Hendrie in US Patent Number US 7,740, 061 B2, granted 22 June 2010, entitled "Externally Activated Seal System For Welihead;" those taught by Cook et. al. in US Patent US 7,147,053 B2, dated 12 December 2006, entitled "Wellhead:" those taught by Berg et. al, in US Patent US 6,698,610 B2, granted 2 March 2004, entitled "Triple Walled Underground Storage Tank;" those taught by Berg, Sr. in US Patent US 6,820,762 B2. granted 23 November 2004, entitled "High Strength Rig for Storage Tanks;" those taught by Wright, et. al. in US Patent US 7,823,635 B2, granted 2 November 2010, entitled "Downhole Oil and Water Separator and Method;" taught by Thompson in US Patent US 7,857,060 B2, granted 2 December 2010, entitled "System, Method and Apparatus for Concentric Tubing Deployed, Artiticial Lift Allowing Gas Venting from Below Packers;" those taught by Choi in US Patent 5,474,601, granted 12 December 1995, entitled "Integrated Floating Platform Vertical Annular Separator for Production of Hydrocarbons;" those taught by Ford in US Patent US 7,703,509 B2, granted 27 April 2010, entitled "Gas Anchor and Solids Separator Assembly for use with Sucker Rod Pump;" those taught by in taught by Williams in US Patent US 7,604,464 B2, granted 20 October 2009, entitled "Mechanically Actuated Gas Separator for Downhole Pump;" those taught by Lal, et. al. in US Patent US 7,645,330 B2, granted 12 January 2010, entitled "Gas-Liquid Separator Apparatus;" those taught by Ehlinger, et. al. in US Patent US 7,849,918 B2, granted 14 December 2010, entitled "Centering Structure for Tubular Member and Methology for Making Same;" those taught by Sizer in US Patent 3,448,803 filed 2 February 1967, cntitlcd "Means for Operating a Well with a Plurality of Flow Conductors Therein;" those taught by Hosie et. al. in US Patent US 7,395,877 B2 granted 8 July 2008, entitled "Apparatus and Method to Reduce Fluid Pressure in a Well Bore;" those taught by Brown in US Patent 2,975,835, filed 11 June 1958, entitled "Dual String Cross-Over Tool;" those taught by Wilson et. al. in US Patent US 7,445,429 B2 granted 4 November 2008, entitled "Crossover two-phase flow pump;" those taught by Fredd in US Patent 4,453,599 granted 12 June 1984, entitled "Method and Apparatus for Controlling a Well;" those taught by Browne et. a]. in US Patent US 6,298,919 Bi, granted 9 October 2001, entitled "Downhole Hydraulic Path Selecfion;" those taught by Edwards et. al. in US Patent US 6,170,578 Bi, granted on 9 January 2001, entitled "Monobore Riser Bore Selector;" those taught by Simpson, et. al. in UK Patent Application publication number GB 2,429,722 A, published 7 March 2007, entitled "Crossover Tool For Injection And Productioll Fluids;" those taught by Zackman, et. at, in UK Patent GB 2,387,401 A, granted 15 October 2003, entitled "Crossover Tool Allowing Downhole Through Access;" those taught by Argumugam, et. al., in US Patent US 7,967,075 B2. granted 28 June 2011, entitled "High Angle Waterflood Kickover Tool;" those taught by Jackson, et.

al. in US Patent Application Publication Number US 2007/0267200 Al, published 22 November 2007, entitled "Kickover Tool and Selection Mandrel System;" those taught by Dinning in US Patent US 3,799,259, granted 26 March 1974, entitled "Side Pocket Kickover Tool;" those taught by Schraub in US Patent Application Publication US 200410060694 Al, published 1 April 2004, entitled "Kick-over Tool for Side Pocket Mandrel;" those taught by Pratt in US Patent US 7,207,390 BI, grantcd 24 April 2007, cntitlcd "Mcthod and Systcm for Lining Multilatcral Wclls," and those taught by Roth, et. al. in US Patent US 6,810,955 B2, granted 2 November 2004, entitled "Gas Lift Mandrel;" each of which is included in its entirety by reference.

[0006] The present invention may use the teachings of Morgan and Sinclair, and Gallagher and Lumsden for hoop stress resistant conduit joint connectors, which due to their cost of manufacture, compared to screwed and coupled connections, are not widely used th most conventional well designs, wherein the present invention significantly improves upon said teaching by applying lower cost hoop stress strengthening to the pipe body. Where Morgan, et. al.. teach large diameter high pressure connectors with exceedingly tight machining tolerances, the present invention teaches lower cost and lower tolerance large diameter high pressure hoop stress resistance sharing conduits that may use hoop stress resistant connectors and wellheads.

[0007] Similar to Morgan, et. al.. Bilderbeek and Hendrie teach the use of hoop stress resistance in a welihead to secure conduit hangers, which is also relatively high cost, with relatively high tolerances of manufacture compared to conventional wellheads requiring less pressure integrity. While the teachings of Bilderbeek and Hendrie may be used within the present invention with, e.g., conventionally sized conduits, the present invention provides significant improvements over said teachings by providing a well conduit system with lower cost and manufacturing tolerance hoop stress resistant conduits below the wellhead as well as an integrated wellhead, that may use large diameter conduits of the well to replace large flanges securing conduit hangers taught by Bilderbeek and Hendrie. Where the teachings of Bilderbeek and 1-lendrie add thick metal large diameter restraining hoops to provide hoop stress resistance for a conduit hanger suspending, or hanging, conventionally sized and pressure rating conduits, the present invention uses the shared hoop stress resistance of large bore conduits to replace the thick metal large diameter restraining hoops taught by Bilderbeek and 1-lendrie, to provide a more efficient conduit system and wellhead.

[0008] Similar to any plumbing compression fittings, Bilderbeek and Hendrie teach the use of a compression olive to hang conduits within a wellhead. The present invention significantly improves upon the teachings of Bilderbeek and Flendrie by providing single olive (41) arrangements suitable for installation of conduits with hoop stress sharing loading sm-faces and double (42) olive (4i) anangements for conduit securing and sealing apparatus between large bore high pressure conduits to at least partially replace thick metal large diameter restraining hoops required for conventional applications of compression olives.

[0009] The present invention may. in some instances, incorporate the lessons taught by Cook et. al., within the inside diameter of the invented novel large diameter high pressure conduit system, wherein Cook, et. al. teach the expanding of conventional sized tubular conduits within a conventional sized welihead 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." [0010] Where the present invention may be considered a re-engineered well design, Cook, et. at, begin with a conventional well design that relates to "apparatus and method [to] further minimize[&] the reduction in the hole size of the well bore casing necessitated by the addition of new sections of well bore casing." As stated by Cook, ct. a!., thcir invcntion "relates generally to well bore casings, and in particular to well bore casings that are formed using expandable tubing, " wherein "The inner and outer diameters of the tubular member 210 may range, for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. hi a preferred embodiment, the inner and outer diameters of the tubular member 210 range from about 3 to 15.5 inches and 3.5 to 16 inches. respectively in order to optimafly provide minimal telescoping effect in the most commonly drilled wellbore sizes. The tubular member 210 preferably comprises a solid member." As is common to the state-of-the-art, Cook, et. at. fail to recognise a need to exceed the illusionary restriction of the maximum conventional rotary table diameter of 49 1⁄2 inches, despite its growing obsolescence with the advent of top drives. Furthermore, Cook, et. al.. teach a "telescoping efftct... [with] tubular member 210 preferably comprises a solid member," that cannot adequatdy use hoop stress sharing, because of said tdescoping effect.

[0011] Cook, et. a!. teach the use of "yield strength of about 40,000 to 135,000 psi in order to optimally provide maximum burst, collapse, and tensile strengths. In a preferred embodiment, the thick wall casing 1510 has a failure strength in excess of about 5,000 to 20,000 psi in order to optimally provide maximum operating capacity and resistance to degradation of capacity after being drilled through for an extended time period." [0012] Accordingly. the present invention is a significant improvement over the lessons taught by Cook, et. al.. because the present invention relies upon a the effective wall thickness of rigid conduits and not expandable ones; for example, if a 48" outside diameter conduit with 2 1/4 inch (") wall thickness is combined with a 54" outside diameter conduit with 2 1⁄4" wall thickness for a 40,000 pound per square inch (psi) matenal and high compression cement is placed about the radial extending loading surfaces that share hoop stress resistance, the arrangement may in combination form a 5.25" effective wall thickness capable of supporting 6800 psi internal yield pressure and 7000 psi collapse pressure, according to a standard API bulletin 5C3 calculation. If an 135,000 psi yield material is used the internal yield pressure, or burst pressure, increases to 22,960 psi and the collapse increases to 23,690 psi with the API calculation. The present invention may, however use many layers, e.g., if a 48" conduit, 54" conduit and 60" all have 2 1/4" wall thickness and an 80% shared hoop stress resistance factor, resulting in an effective wall thickness of 80% of 8.25" or 6.6", then a 40,000 psi yield material corresponds to a 7700 psi burst and 7832 psi collapse pressure, while a 135,000 psi yield material corresponds to a 25,980-psi burst and 26,430-psi collapse pressure using the API bulletin 5C3 calculation.

Accordingly. the present invention not only provides higher conduit burst and collapse pressure, but also usable space within the conduit for vanous applications including, e.g., a plurality of wells from a single welihead and well bore fluid processing with separation and heat exchanging apparatuses. Accordingly, applying loading surfaces along the axial length of two adjoined conduits and using their abutment to share hoop stresses represents a significant improvement over cemented centralizers taught, e.g., by Ehlinger, et. al. because, while cement has compressive strength it does not possess sufficient dasticity and it is not the practice in conventional well design to rely on the intermittent placement of centralizers within cement for increase pressure bearing capacity due to the natural uncertainties of engagement between casings.

[0013] Also, while the teachings of Berg et. al and Berg Sr., relating to ribbed cylindrical walls for subterranean tanks may be used with the present invention, in very limited instances, the present invention represents a significant improvement because Berg Sr. and Berg, et. al. teachings primarily relate to shallow tanks for service stations storing already processed hydrocarbons and not subterranean tanks used for processing and engaged between a wellhead and subterranean deposits, wherein installation during drilling and securement to a wellhead or the interaction with processing apparatuses, e.g., separators and heat exchangers, are not taught by Berg Sr. and Berg. et. al. Additionally, the pressure experienced within shallow subterranean storage tanks for already processed hydrocarbons, which are not connected to high pressure and large volume hydrocarbon reservoirs, are relatively insignificant compared to, as described above, the required burst and collapse pressures associated with well construction and operation, wherein the teachings of Berg Sr. and Berg, et. al., are not necessarily applicable.

[0014] Additionally, while various aspects or features of the teachings of Wright, et. al., Thompson, Choi, Ford, Williams and Lai, et. al., relating to various forms of downhole separation, processing and stimulation, are usable with the present invention, the large diameter high pressure separation, processing and simulation features of the present invention represent a significant improvement over such prior art, because, for example, usable downhole volumes are greater and allowable pressures are higher within the large diameter and high pressure bearing capacity of the present invention, wherein environmental energy may also be used with the larger volumes and higher pressures, making a high pressure fluid pump and/or compressor possible. Integration of apparatuses and methods of the present inventor. e.g., chamber junctions, bore selectors and manifold crossovers, also allows 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 welihead connections.

[0015] The present invention also significantly improves upon the teachings of Sizer and Brown, which are conventionally usable for a limited range of substantially water or substantially hydrocarbon wells due the lack of a large diameter high pressure conduit system for comp'etion operations producing hydrocarbons and/or water from the strata through the well bore, and wherein significant improvements are also provided over the combination of the teachings of Hosie, relating drilling strings that are usable for substantially heavyweight drilling fluid boring operations to prevent the flow of hydrocarbons or water from the strata into the wefibore.

[0016] The teachings of Sizer, Brown, Hose, Wilson et. al., Browne et. al., Fredd, Edwards et. al., Simpson et. al., and Zackman et. al. are limited by the inability of large diameter conduits to bear high pressures and hence are restricted to conventional sized wells, wherein the present invention provides the significant improvement of providing more space within a well conduit system for apparatus and method, wherein apparatus and methods of the present inventor in PCT US2O1 1/000377, GBii04278.5, PCT U52011/000372 and GBiiO428O.I, providing concentric conduit configures p'aceable within conventional sized wells and thus providing

B

significant improvement over Sizer and Brown's smaller and less efficient autonomous parallel arrangements within conventionally sized wells, may be further improved with a larger diameter higher pressure conduit system to house either concentric or autonomous conduits that can be usable to improve flowing capacity within the passageway through subterranean strata for producing and injecting simultaneously flowing fluid mixture streams of various velocities, whereby single bore and plurality of bore drill through weliheads and associated valve trees for landing completions may be used with various axially concentric and axially autonomous arrangements. apparatuses and methods, including a manifold string of the present inventor, to improve the efficiency of both drilling and comp'eting one or more wells through the single main bore of said large diameter high pressure conduit system of the present invention.

[0017] The present invention also provides significant improvements over the teachings of Argumugam, et. al., Jackson, et. aL, Dinning, Schraub, Roth, et. al.. and Pratt, which generally deal with kick over tools for side pocket mandrels used in relatively small holes sizes for placement of various flow apparatuses, but not designed for side-tracking of wells with a drill string, wherein the large diameters of the present invention provide the necessary enlargement to facilitate the practica' application of a whipstock side pocket mandrel for multi-lateral boring of wells. The combination of such lessons with the pnor art or conventional multi-lateral technologies is not obvious because, insufficient space exists within conventional well designs for axially and circumferentially autonomous (34) bores of, for example, 6" or S A" diameters and as taught by Pratt, prior art multi-Iatcral tcchnology rclatcs to "tie-back systems that provide increased strength against collapse of a lateral well bore junction." The present invention provides significant improvements because it provides for larger hole sizes and ability to access a lateral with a kick-over tool while providing pressure integrity and resistance to collapse equivalent to the primary bore of a conventional well design.

[0018] The present invention may also be used with the teachings of the present inventor in GB247i76OB and 0B1021787.5 for rotatably placing and cementing larger bore conduit and manifold strings with a fluid mixture, or heavyweight drilling fluid slurry, wherein the installed conduits, crossovers and manifold strings may be intermediately hung from a welihead using an olive arrangement during well formation, and wherein they are also usable after well formation with substantially hydrocarbon or substantially water fluids, wherein apparatus and method of placing conduits and/or manifold strings during drilling may also be applied to completion operations through a arge diameter high pressure conduit system using apparatuses and methods of the present inventor or conventional methods and apparatuses through axially autonomous well bores, to more cost effectively provide a plurality of wells through a single main bore.

[0019] Additionally. while. the present invention may be applied to various subterranean deposits, an example application using the presently popular topic of shale gas, requiring low cost apparatus and method for development due to lower recovery rates, is provided herein, to further distinguish the preferred features of the present invention from conventional practice and prior art, wherein reference is made to the teaching of Bruner and Smosna in the US Department of Energy Document DOE/NETL-201 i/i478 entitled A Comparative Study of the Mississippian Barnett Shale. Fort Worth Basin. and Devonian Marcellus Shale. Appalachian Basin, published April 2011 on the world wide web at (http://www.shalegas.energy.gov/resources) at the time of filing and included in its entirety by reference, and wherein, for such applications, the present invention is also generally usable to meet the First edition October 2009 API Guidance Document HFI entitled "Hydraulic Fracturing Operations -Well Construction and Integrity Guidelines." also published on the same website at the time of filing.

BACKGROUND

[00201 The present invention usable for injectable and producible strata within conventional and unconventional subterranean deposits, e.g., a strata layer for depositing waste water or preforming water floods, salt deposits for consumption and/or caverns, geothermal deposits for steam and hydrocarbon deposits for medicines, plastics and energy, wherein the present invention relates, generally, to apparatus and method of a well conduit system with large diameter higher pressure subterranean placed conduit system for containing fluid communication conduits, wherein said containment comprises conduits with continuous ci asticafly compressible outer and expandable inner pipe body circumferences having radial loading surfaces abutting one conduit to another, and wherein the effective diameter of one is greater than the other, prior to said abutment adjoining said radial loading surfaces to share hoop stress resistances between conduits with said abutment, to form a greater effective wail thickness capaNe of bearing higher pressures to, in use. contr& fluid communication between injectable and producible strata of one or more well passageways extending between at least one wellhead assembly and said strata through exits at the lower end of said large bore high pressure conduit arrangement.

[0021] Said well conduit system may comprise, in part, adapted apparatuses of the present inventor, which are generally descnbed in UK Patent 2465478, entitled "Apparatus And Methods For Operating A Plurality Of Wells Through A Single Bore;" teaching a plurality of wells through a single main bore; United Kingdom patent application having Patent Appfication Number GBl02l787.5, entided "Managed Pressure Conduit Assembly Systems And Methods For Using a Passageway Through Subterranean Strata," lodged December 23, 2010, teaching the carrying and placement of large bore subtelTanean conduits with a drill string; and UK Patent 2471385, entitled "Apparatus and methods for forming and using subterranean salt cavern," teaching improvements in fluidly accessing a salt deposit and whereby large bores are conventionally practice, albeit without the significant improvements of the present invention; wherein each are included in their entirety by reference.

[00221 The present invention focuses, generally, the need for a step change in the productivity of well designs accessing solution mining, geothermal and, particularly, hydrocarbon deposits within the industry of hydrocarbons, energy and greenhouse gases, as descnbed by Daniel Yergin in The Prize: The Epic Ouest for Oil. Money, and Power, as published in New York by Simon & Schuster in 1991 and The Ouest: Energy, Security, and the Remaking of the Modern World, as published by Penguin Press in 2011, both of which are included in their entirety by reference, to establish the general state-of-the-oil-and-gas-industry, its focus on large low cost production, standardization and the importance of innovation to our world with regard to energy and greenhouse gases.

[0023] The importance of innovations in energy and greenhouse gas reductions may also be found on various websites, for example http://www.eni. comlen_IT/innovation-technology/technological-answers/maxirnize-recovery/m axirnize-recovery. shtml, provided by ENI, a major oil and gas producer, describing that the present world average recovery factor from oil fields is 30-35% (versus 20% in i980). wherein this parameter may range from a 10% average of extra heavy crude oils to a 50% average of the most advanced fields in the North Sea. ENI further states that increasing the "recovery factor" by only 1%, even without the discovery of new fields, could increase world reserves by 35-55 billion barrels or about one or two years of world oil production. Hence, the recovery of reserves beyond those conventionally available may be considered an unconventional hydrocarbon, despite being produced

from the same field as conventional hydrocarbons.

[0024] Additionally. ENI believes that improvements in well recovery factors have a positive environmental effect, for example. 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).

[0025] ENI thither states that "It becomes fundamental to exploit the most advanced drilling and development techniques, as well as recovery processes, whether 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." [0026] Accordingly. a need exists for smarter well design and intelligent well systems to increase recovery and protect the environment through re-use of infrastructure andlor inclusion of computer controlled production systems (108 of Figure 17) to maximize reservoir pressure management and production. A need also exists for maintaining reservoir pressure and better managing of unwanted subterranean fluid production.

[0027] As autonomous flow, autonomous annuli and well integrity are a key design focuses iii conventional applications during production and injection of all subterranean wells, particularly in regulator regimes that require such autonomous characteristics.

a need exists for: i) isolation of the innermost conduit, or primary bather, protecting the surface and subsurface environment and ii) isolation of the produced or injected fluids within the well with the intennediate annular space between barriers fluidly monitored. A further need exists for the use of proven production and injection isolation methods and apparatuses within more intelligent well designs.

[00281 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., concentric outside diameter 30" conductor surrounding 20" and 13 3/8"intermediate casing and 9 5/8" production casing, and potentially a 7" production liner, containing injection and/or production tubing sized between 3 1/2 and 5 1⁄2". In, for example, conventional hydrocarbon extraction with a permeable sandstone or carbonate reservoir having significant quantities of recoverable fluids, this conventional design is both practical and cost effective. However, use of conventional designs on unconventional production and/or injection wells may not provide the most effective design from an environmental, cost and/or recoverable reserves perspective. e.g., when geologic conditions of strata stability, pressures.

temperatures, strata fluid isolation and the depth of wells stretch conventional designs beyond their onginal objectives, which were characterized, as described by Yergin, as relatively large and low cost deposits.

[0029] A need exists for increasing the size of wells to incorporate more than one well within an isolation conduit to reduce the number of penetrations through ground water and cap rock formations, thus protecting environment above from the fluids and pressures below.

[0030] The layering of strata over geologic eras, epochs and penods comprises various permeable and impermeable layers or formations, which aho represent horizons where fluids may migrate horizontafly, but are trapped vertically by impermeable overburden formations. Production wells, by necessity, must penetrate these inipermeaNe sealing formations or cap rock above the target producible or injectable horizons, which traditionally have been permeable sandstone or carbonate hydrocarbon reservoirs that may be recovered economically with a series of single bores and concentric conduits. The convention in regard to using the term "economically," is, however, focused entirely on discounting the future value of said hydrocarbons.

[0031] A need exists for efficiently accessing, isolating and re-entering a plurality of permeable geologic formations with injectable and/or producible horizons between a corresponding plurality of impermeable formations at an economic cost.

[0032] Accordingly, the stated-of-the-energy-industry, as described by Yergin. has been and presently continues to be pre-occupied with finding, developing and recovering 30- 35% of very large hydrocarbon deposits at the lowest costs, which generally necessitates the use of relatively simp'e and common proven technologies and single concentric bore wells. However, the attitude of Eni and others may be changing in favour of using new technologies to increase recovery rates, wherein such increases may also significantly benefit nations with historic hydrocarbon deposits.

[0033] If the recovely rate range provided by ENI, between 10% for unconventional heavy oils to 50% for advanced recovery of conventional oil and gas with an average of 30- 35%, is indicative of a normal distribution and the present state-of-the art, then approximately 70% of worldwide reserves will not be recovered and the impact of enhanced recovery is indeed significant even for small changes, as EM highlights.

[0034] As the number and physical size of well bores and permeable pore spaces are the links to enhancing recovery, improving either will significantly affect producdon, wherein more well bores within a producible deposit, with permeability improvements from proppant fracture technothgy and water injection to supplement pressure depletion. may constitute a step change in recoverability of valuable subterranean fluids.

[0035] A need exists for an efficient well design usable to increase the recovery rate of both conventional and unconventional deposits of hydrocarbons through the increased proximity of well bores to producible strata that may require fracturing of the strata with proppants to increase said strata's permeability to produce fluids while injecting fluids, water and/or produced water back into the strata to supplement the pressure depletion of producrion with said injection.

[0036] Additionally, the integnty of the strata may degrade with the pressure of depletion and result in, for example, subsidence within the strata and potentially at surface if the overburden does not bridge across said subsidence. While water injection or flooding of the subtelTanean 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 andlor injection zone. Unfortunately, instability within the strata may prevent future drilling through strata affected by this instability and the ability to place well bores for future production may be lost.

[0037] An need exists for more efficient well design capable of managing differing injection and production pressures associated with exploiting all of the vertically stacked producible and injectable strata horizons within an proximal area of, for example, a salt production deposit, solution mining salt deposit, geothermal steam deposit and/or substantially hydrocarbon deposits from initial completion of a well to avoid strata subsidence and stability preventing future drilling.

[0038] The present state-of-the-art for low cost recovery well designs, apparatuses and methods are such that standardization not only applies to concentric single bore well designs, apparatuses and methods practiced. but also to skilled persons of the art of upstream hydrocarbon exploration, extraction and well site processing.

Standardization also applies to disciplines within the art, if not the practioners themselves, who development such skills in segregated silos of drilling, completion and production, wherein mastering the art does not necessarily involve mastering each of the drilling, completion and production skill sets, but rather mastering the methods and apparatuses within each silo using a standard set methods with standard sized apparatuses. 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. Indeed, practioners may be criticised as heretics for stepping out-of-the-box, especially with regard to questioning the bore hole and conduit sizes on which the entire industry is built.

[0039] Historic market forces and fluctuations between the boom and bust pricing of hydrocarbons have forced companies to focus on the current day, and not on the future, wherein low cost production has retarded the employment and training of practitioners to the point where artisans capable of bridging between the afore mentioned silos are few and far between and wherein each specialized silo delivers a standardized product that is accepted, generally without question. For example, the practioners within the sUb of completions rarEly question the product dElivered by the silo of drilling, albeit the perpetual argument about skin damage to the reservoir and the amount of debris left within a bore hole to be completed, hence innovation across the disciplines is practically non-existent.

[0040] The present state-of-the-art and the need to standardize apparatus, method and the disciplines of those skilled in the art to conventional large scale deposits, without consideration of the future unconventional deposit which must now be developed, may simply be the residue of historic supply and demand conditions, described by Yergin, and which drove a need for the same proven low cost methods of standardization used on Henry Ford's assembly line or in Fredrick Winslow Taylor's methods for optimising the efficiency of the human machine, described in The Principles of Scientific Management. Unfortunately, the present state-of-the-art may not necessarily be ananged to meet the need for innovations, as proposed by Yergin and ENI, for various reasons, including the merging of competitors within the industry to reduce transaction and overhead costs, but resulting in an oligopolistic industry structure and/or market failure, wherein industry pnoritizes standardization over investment in innovation, particularly across the disciplines of drilling and completion. Accordingly, the apparatus and method taught herein are not obvious, because historic market forces have failed to or have only just begun to provide the necessary incentives to make such innovations applicable within the industry.

[0041] A need exists for a step change in the efficiency of utilizing subtelTanean mineral and geothermal deposits that requires breaching the conventional boundaries of well construction and operation practice, wherein optimization and innovation within professional disciplines of well construction and operation silos of knowledge exist, but wherein innovation across said silos of knowledge generally does not.

Accordingly, the present invention provides a complete well conduit system that is neither obvious nor practiced by professionals of well construction and operations, despite prior teachings related to individual components, because said practioners do not, generally, practice the conventional or prior art apparatuses and methods used prior to or after their particular area of expertise and, hence. are ill equipped to connect technologies across the entire well drilling, comp'etion and production process.

[0042] As described, innovation, at least across disciplines, has been less important than standardization in the historic market dominated by over-supply or the present oligopolistic market where insufficient competition exists to sufficiently drive the development of new technologies until dramatic events such as climate change and peak or plateau oil production occur. As described by Yergin, the oil industry has gyrated between boom and bust throughout its history, whenever the supply of discovered large hydrocarbon deposits was left uncontrolled to flood the market and dramatically lower price, or overly restricted to dramatically increase price, wherein it is beneficial for companies within the market to merge or collude to control the market, wherein standardization is a primary tool for lowenng costs.

[0043] A need exists for a creating a new standard for well design that may be used across the majority of conventional and unconventional subterranean deposits, and which uses to the largest extent possible, existing proven and standardized dnlling rigs, equipment and methods, which are familiar to practioners skilled in art, wherein said practitioners are not restricted to historic conduit sizes and/or a single concentric well bore per wellhead.

[0044] Accordingly. the standardization of apparatuses within the upstream industry is so prevalent that even when equipment no longer provides a primary function, e.g..

when the rotary table of a drill rig is made obsolete by the installation of a top drive, its size is maintained bdow 49 1⁄2 inches in diameter. While historic versions of a kelly with a kelly bushing and rotary table are still used today, for various reasons, top drives are generally superior. Such size standardization of relatively obsolete equipment is suboptimal as, for example, the larger diameter conduits and wellheads of the present invention may be installed more easily using a rig's derrick, if the diameter of an obsolete rotaly table is increased, without adversely affecting the functionality of the rig or the use of other standardized equipment to maintain a low cost structure.

[00451 A need exists for locating the minimum necessary changes to conventional well design that will yield the most improvement, while maintaining the present standardization and resulting low cost solutions.

[00461 It is further proposed herein that said standardization in the oil and gas industry has been, to the largest extent, driven by the higher per unit value of oil and/or easily producible sandstone and/or carbonate reservoirs with high porosity and/or permeability, wherein the significant portion of future hydrocarbon production may come primarily from hydrocarbon gas trapped within relatively impermeable shale, which, as described by Yergin, is the most important discovery to occur in this century.

[0047] A need exists for improved access and recovery of conventional and unconventional hydrocarbon deposits, e.g.. those in very deep water wells, very high pressure wells.

viscous tar sand hydrocarbons, relatively impermeable sandstones and/or shale gas deposits.

[0048] For example. the effecrive production of a shale gas deposit requires high pressure injection and fracturing with low friction "slick" water chemical mixtures to carry fine sand proppants that split tight shale layering to allow gas to escape from shale gas deposits along its bedding planes to fractures transverse to said bedding planes.

which lead to perforation tunnels in an injection/production conduit of a well.

[0049] Since 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, wherein produced fluids like hydrocarbon gas are particularly explosive, stringent analysis and execution of well construction and integrity is of key importance in containing injection and production fluids.

Reducing the risk of potential leak paths as low as practicably possible to prevent well leaks to the environment is particularly important to the health of above ground inhabitants and plant life, including protection of the ground waters that they need to survive.

[00501 With the development of unconventional hydrocarbons, e.g., tar sands with toxic by-products accompanying fluids released by steam injection or tight sandstones and shales requiring man-made hydraulic fractures techniques using toxic chemicals and/or propane and other stimulation fluids and proppants, come additional well integrity challenges not found in conventional hydrocarbon development.

[00511 A need exists for managing both pressures and fluid injected and/or produced from a subterranean well, which not only includes pressure and fluid integrity, but also basic handling and/or processing of fluids at the well site within a safe environment.

[0052] Furthermore, with regard to fracturing technology and improved recovery, as described by Bruner and Smosna, a recovery rate between 7% and 20% for Marcellus and Bamett shale gas deposits may be expected, wherein "simultaneous fracs and zipper fracs between neighboring horizontals have proven successful in preventing communication between the fracture fairways and to maximize borehole contact with the reservoir. A simultaneous frac involves two wells that are fractured together. Gottschling (2007) described a simultaneous frac in which the wells were ft apart on the well pad and 1000 ft apart at the toe. One was fractured in 4 stages and the other in 5 so as to prevent communication between the fracture fairways. These wells yidded a significantly higher initial potential than individuafly fractured offset wells." Accordingly, a further need exists for more efficiently performing simultaneous subterranean hydraulic fracturing operations to improve recovery and minimizc thc latcr dcscribcd "teak-off' of prcssurc or undcsircd pressure drops during hydraulic fracturing addressed by said simultaneous fracs.

[0053] A wclI's dcsign and construction must minimizc thc risk of Icaks through or bctwccn any casing strings. The fluids injected and produced from a well, e.g., injected fracturing fluids and produced oil, natural gas liquids, or gas and water, must travel through the strata and past ground water formations to the wellhead.

[0054] Conventional well construction emphasizes the existence of at least two barriers between subterranean pressurized fluids and the surrounding environment, wherein 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 subtelTanean strata and cap rock containing a producible or injectable strata horizon after well construction.

[0055] A need exists for greater integrity between injected/produced fluids and the environment, both during and after well construction.

[0056] The selection of the materials for cementing and casing are important considerations for is&ation of subterranean injected and produced fluids, but are, generally, less significant than the placement of cement with respect to protecting the surface environmental and groundwater horizons. A need exists for better cement placement methods and apparatuses to provide improved well integrity.

[0057] Additionally, well designs generally include contingency options to increase the reasonable probability of successfully constructing a well while mitigating or eliminating the nsk of unplanned releases of injected or produced fluids, or failure to complete a well due to unplanned events. Construction of the well design generally comprises sequentially drilling and placing successive casings, wherein mitigations often involve installation of additional casing strings during drilling.

[0058] A need exists for wells with greater flexibility and more contingency options with respect to encountering unexpected subterranean adversity to well construction, production and/or injection.

[0059] Drilling of a well generally comprises the use of a drilling sting with at least i) a drill bit, ii) one or more stabilizers forming a crude bearing for rotating the drill string more or less centrally with the bored hole, iii) drill collars with thick heavy walls usable in compression for placement of weight on the bit, and iv) drill pipe usable in tension to suspend the drill string within the bored hole, wherein the apparatuses below the drill pipe are generally referred to as a bottom hole assembly (BHA). The drill string is suspended by a derrick or mast when operated during drilling to control the weight on bit and when placed and retrieved from the casing and bore hole, which is generally referred to as running in or pulling out of the hole.

[0060] The drill string is then rotated by the use of a turntable (rotary table), top drive unit, and/or downhole motor drive, wherein the use of a top drive is generally preferred by practioners, since the rotary table cannot provide the same technical functionality.

However, since the capital investment in power systems to drive a rotary table are less than those of a top drive and the operating costs of contractors are passed on to operators and, ultimately, the public in small increments over large volumes of produced fluid, the use of inefficient equipment, like the rotary table, continues today.

[0061] A need exists to more effectively carry out drilling operations and reduce the cost of providing a plurality of weBs to access unconventional subterranean deposits, for example, a hydrocarbon deposit, solution mining salt deposit or geothermal deposit.

[0062] Drilling fluid, generally comprising a mixture of water. clays, fluid loss control additives, density control additives, and viscosifiers, is circulated down the drill string and up the space between the drill string and hole to lubricate the drilling assembly, remove the formation cuttings driBed, and maintain pressure control of the well, which also stabilizes the bore hole wall.

[0063] A need exists for more effective using of well construction fluids, for example, drilling mud that may be 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.

[0064] Conductor pipe or casing may be driven into place with a large hammer, like structural pilings, or a bore may be drilled for its installation. wherein the conductor may have a welthead at its upper end, or it may provide a stable bore for a subsequent casing and wellhead.

[0065] After placement of the initial conductor, constructing a subterranean well generally comprises several cycles of drilling or boring into the subterranean strata, placing steel pipes or conduits called casing, and cementing 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 previous installed casing.

[00661 Conventionally, shallow portions of the well have multiple concentric strings of steel protective linings or casing installed with intermediate fluid filled annuli and casings between the conductor and final casing string The number of intermediate casing strings is deteimined by the geologic era, periods, epochs and formations being penetrated, wherein subterranean strata layers have differing strengths that may fracture and prevent drilling fluids from being circulated, hence intermediate casings must be placed to protect weaker formations from higher pressure subterranean formations and circulating pressure of the drilling fluid column.

[00671 As unconventional subterranean deposits, for example, those in deep water, deep subterranean depths, viscous tar accumulations and shales. may, by definition, have unconventional geology, a need exists for additional options for provision of protective linings or casings.

[0068] The inclination of wells may vary between vertical and horizontal, wherein horizontal weBs are drilled vertically to a point and then directionally drilled to form a substantially horizontal well bore. generally. targeting a horizontal formation for injection or production. The vertical portion may be drilled with various methods, but directional drilling to turn and/or incline a well bore conventionally involves use of a pendulum drilling assembly, which typically uses bent housings. downhole motors andlor rotary steerable systems.

[0069] Generally, the final portion of the well construction cycle is the evaluation of the production or injection zone and the placement of one or more production conduits, comprising liners and a production conduit generally referred to as tubing, wherein conduits installed at the end of the well construction are generally used to fluidly communicate injected and produced fluids.

[0070] Isolating a particular portion of the well bore from another, for the purposes of injection and/or production, generahy involves cementing a casing in place and perforating the casing and cement at the desired location, thus isolating injection and production from that specific location from other portions of the well bore or subterranean strata.

[0071] Various stimulation operations may be applied to an injection and/or production reservoir or horizon, e.g., focusing injected fluid pressure to carry proppants, such as sand, through the small orifice of a perforation is used to fracture and hold or prop open strata to increase its permeability, which is generally referred to as hydraulic fracturing.

[0072] A need exists for improving directional and horizontal drilling, including accessing previously placed bores, for both conventional and unconventional subterranean deposits.

[0073] The significance of the well design, including the selection and installation of the casing, tubing and cement, is important given the explosive nature of injectable and producible hydrocarbons communicated through the well bore under pressure, wherein conduits must withstand the various compressive, tensional, and bending forces exerted upon them during installation as well as the collapse and burst pressures during operation with a reason margin for safety.

[0074] For example, during cementing operations, the casing must withstand the hydrostatic forces exered by the cement column after which it must withstand the collapsing pressures applied from subsurface formations, which are generally equal or greater to the hydrostatic pressure of a column of water at the subterranean depth in question, unless, for example, depletion from production has lowered such pressures.

Depletion within a horizon below the pressures of the surrounding strata exerts overburden and/or other pressures, which may cause instability within rock formations, especially those that may react adversely to entering fluids, e.g. water, or that are faulted or fractured. Fluid pressures in higher zones seek to equalize with depletion to cause a change in the previously pressure supported subterranean strata arrangement.

[0075] Generally, casing used within oil and gas wells follow ISO and API standards that cover the design, manufacturing, testing, and transportation. Such casings are manufactured to such specifications to meet strict requirements for compression, tension, collapse, and burst resistance, quality, and consistency. The casing used in a well should be designed to withstand, for examp'e, the anticipated hydraulic fracturing pressure, production pressures, corrosive conditions, and other factors.

[0076] To minimise the cost of casings they are, generally, threaded on each end with a coupling installed to join one casing to another, wherein when severa' joints of casing have been screwed together they form a continuous "string" of casing that may be cemented in place to isolate the hole. However, coupled connections are, generally, derated for temperature and compression forces, wherein snap together connections, which are generally more expensive, may be stronger than the pipe body they connect.

[0077] The snap together connections, for example, those taught by Morgan and Sinclair and Gallagher and Lumsden, may use hydraulic forces to expand one circumference of a connection and compress another to allow a tool to snap together, after which the hydraulic forces are removed. These snap together connections use the hoop stress resistances of the internal pin and external box portion of the connection to hold the connection together.

[0078] A need exists for higher pressure casings and larger diameter casings using hoop stress strengthening that may, for example, be installed within deeper formations so as to prevent the premature downsizing of a well bore to, for example, allow two well parallel wellbores for side-tracking of a plurality of wells from the dual well bore arrangement.

[0079] After the casing has been placed. it must be cemented in place. This critical part of well construction provides zonal isolation between different formations, including, for example, isolation of groundwater horizons and to provide structural support of the well, wherein said cement is fundamental iii maintaining integrity throughout the life of the well and forms a part of corrosion protection.

[0080] Conventionally, cementing is accomplished by pumping the cement down the inside of the casing and circulating it back up the outside of the casing. Top and bottom rubber wiper plugs may be used to minimize mixing of cement with drilling fluid while it is being pumped. Analysis of the cementing parameters and hardware, for examp'e, float equipment and centralizers, is also used to increase the probability of isolating unwanted fluids and pressures, albeit centralizer do not strength the pressure bearing capacity but do urge cement to flow around the entire circumference of the conduit.

[0081] The first casing to be installed is, generally, a conductor casing. The conductor casing serves as the foundation for the well to hold back the unconsolidated surface sediments during drilling and to isolate shallow groundwater. Below the conductor casing there is harder, more consolidated rock. The conductor casing may also protect the subsequent casing strings from corrosion and may be used to structurally support some of the wellhead load.

[0082] The conductor hole may be drilled and steel casing inserted into the hole then cemented in place, or the casing is hammered into place with soils and the internal diameter of the conductor is then drilled. When cementing conductor casing, cement should be urged back to the surface. In instances where cement cannot be urged back to surface after being pumped through its interna' passage, it may conventionally be possible to run a small diameter pipe between the hole and the conductor casing to pump cement around the outside of the casing, which is generally referred to as a "top job" or "horse collar." [0083] A need exists for improved cementing of larger annuli to provide well integrity and isolation from subterranean strata for various well conduits.

[0084] After the conductor pipe is installed and cemented, 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. The surface hole may be drilled using air, freshwater, seawater, or water-based drilling fluids. This setting depth can be from a few hundred feet up to 2000 ft deep or more. Conventional practice suggests that surface casing be set at least 100 ft below the deepest permeable water horizon encountered while drilling the well with the surface casing cemented from the bottom to the top, wherein "top job" cement jobs may be necessary in certain situations. In instances where the surface casing cannot be run deep enough to cover the deepest groundwater aquifer, additional strings or a combination of surface, intermediate, and/or production casing and cementing may be used.

[0085] A need exists for both increases in recovery of tluids within subterranean deposits and fewer main well bore penetrations through ground water horizons, which cannot be accomplished with a single concentric bore production well design, because increased rates of recovery, generally, require additional wells or penetrations through groundwater formations and cap rock containing toxic tluids, thus increasing the risks of leakages to said ground waters.

[0086] After cementing a casing and prior to drilling out, the casing is generally pressure tested to confirm casing integrity. Immediately after drilling out of the casing into a short interval of subterranean strata, a formation pressure integrity test or formation leak-off test may be performed to determine if remedial repair of the cement is needed with injection of cement or cement squeezes around the casing and strata about the casing.

[0087] The process of drilling, casing and cementing is repeated to isolate subsurface fluids and formations that may cause borehole instability and to provide protection from abnormally pressured subsurface formations and pressure honzons.

[0088] Prior to the completion of drilling, a production and/or injection bore will be drilled and logged to confirm that the desired subterranean deposit is present prior to placing and possibly cementing a final protective lining. The final lining is cemented when, e.g., a formation is to be fractured and propped open with sand to provide the pressure integrity necessary to propagate the desired fracture orientation without affecting any other geologic formations or horizons in the well. Generally, the production casing string cement does not need to be brought completely to the surface, wherein a sufficient vertical height above, e.g., the highest formation where hydraulic fracturing will be performed maybe sufficient for is&ation.

[0089] As described by Yergin, the technical advancements in drilling and completing honzontal wells are one of the most significant developments in the last 30 years, wherein a horizontal bore through a deposit may improve production performance and allow operators to develop subterranean deposits and resources with significantly fewer wells than may be required with vertical wells. Operators may drill multiple horizontal wells from a single surface location, albeit the conventional concentric bore restricts drilling to a single well, which may greatly reduce the cumulative surface impact of the devdopment operation. However, horizontal wells are significantly more expensive to drill and maintain. In some areas, the typical cost of a horizontal well may be two to three times the cost of a vertical well.

[0090] Horizoiltal wclls arc typically drilled vcrtically to a "kick-off' point whcrc thc drill bit is gradually turned from vertical to horizontal along a desired three dimensional trajectory, comprising vertical, horizontal and lateral coordinates or azimuthal orientation. Various arrangements of casings may be present. including, in some instances, leaving the bore unlined across a deposit or "open-hole." Alternatively, slotted or pre-perforated steel linings may be placed in the open-hole portion as a "production liner" or a continuous liner may be placed, cemented and then perforated to, for example, hydraulically fracture a deposit.

[0091] A need exists for a plurality of horizontal well bores from a single penetration through ground water formations to increase the recovery rates of fluids from subterranean deposits.

[0092] Hydraulic fracturing is a well stimulation technique that has been practiced since 1947 to fracture very low permeability formations such as shale with plate like bedding planes and sandstones with fine grains that limit porosity and/or few interconnected pores spaces, i.e. low permeability. Matrix fracture stimu'ations may involve reactive fluids, such as acid, etching porosity into a deposit or water dissolving salt, or a matrix may be formed by connecting natural fractures with artificial hydraulically created proppant fractures stimulations that, generally, fracture rock then prop it open with proppants, like sand.

[0093] Permeability represents the ability for a fluid to flow through porous rock. For natural gas or oil to be produced from low permeability reservoir deposits, fluid must find its way through a tortuous path andlor past potentially clogged pore space throats to the well bore for communication to surface through well conduits. Without hydraulic fracturing, ow permeability formations may be uneconomic to produce, hence artificial fracturing is an important technology for future energy needs.

[0094] Hydraulic fracturing involves pumping into the production casings or linings, through perforations or open hole if selectively directing fractures is not required, to the strata at fluid pressures sufficient to cause the rock to break open and fluids to be injected. As high-pressure fluid injection continues, this fracture may continue to grow, or propagate, wherein the fluid pump rate must be sufficient to propagate the fracture for proppant placement. As the fracture continues to propagate, a proppant, e.g. sand, is added to the fluid. When pumping stops or when proppants can no longer be forced into fractures and screen out occurs, pumping is stopped and the excess pressure is removed, wherein the fracture may attempt to close. Once any excess proppants are cleared from the well and a fluid communication conduit is available or installed, proppants keep the fracture open and allow fluids to flow more readily through propped fractures in the deposit.

[0095] During hydraulic fracturing fluids may enter the targeted formation adjacent to the created fracture thus causing a leak-off of pressure. The fluid that leaks off can flow into the micropore, pore spaces of the formation being fractured, existing natural fractures and/or into smaller side fractures opened and propagated into the formation by the pressure in the induced fracture, wherein fractures propagate along the path of least resistance. Generally, hydraulic fractures are formed in a direction perpendicular to the least stress. At shallow depths the earth's vcrtical ovcrburdcn pressure is the least principal stress and fracturing, generally, creates horizontal fractures at depths less than 610 metres or 2000 feet. As depth increases.

overburden stress in the vertical direction may increase by approximately 1 per-square-inch per foot, and fractures will be perpendicular to this stress, or in the vertical orientation at depth greater than 610 metres or 2000-feet, wherein azimuthal stiess orientations are aho present and fracture fairways may be formed by first fracturing vertically then vertically in a lateral direction to form a fracture fairway that may extend over hundreds of metres or thousands of feet laterally and 46 to 92 metres or 150 to 300 feet vertically from the well bore depending, obviously, on the regional and depth specific geology.

[00961 Hydraulic fracturing was first used in the late 1940s and has become a common technique to enhance the production of low-permeability formations, especially unconventional reservoirs--primarily fight sands, coal beds, and deep shale deposits.

[0097] Hydraulic fracturing is a technically complex process. In horizontal shale gas wells, fracturing is done in multip'e stages. starting at the "toe" of the well, which is the wcll's horizontal cnd and procccding toward thc "hccl" which is thc cnd closcst to thc wcll's vcrtical portion.

[0098] A wellbore that extends 1,500 metres to 5,000 feet laterally within a shale layer might be hydraulically fractured in ten to fifteen stages several hundred feet apart.

Each perforation interval is is&ated in sequence so that only a single section of the well is hydraulically fractured at a given time and to prevent damage to other sections of the wellbore.

[0099] During a hydraulic fracturing operation, fracturing fluid is pumped at high pressure through perforations in the section of the casing. The chemical composition of the fracturing fluid, as well as the rate and pressure at which it is pumped into the shale formation, are tailored to the specific properties of each shale and, to some extent, each well. When the pressure increases to a sufficient level, a planar hydraulic fracture opens in the rock, propagating more or less perpendicularly to the path of the wellbore.

[0100] A typical hydraulic fracture may propagate horizontally about 500-1000 feet away from the well in each direction. The fracturing pressure is generally controlled, by cap rock or hydraulic fracture design, to prevent vertical propagation beyond the thickness of the layer of gas-producing shale, The pressure needed to propagate the hydraulic fracture vanes and depends on depth, the pressure of the gas in the pores of the shale, and other factors.

[0101] One recent and significant discoveiy made while working in the Barnett Shale was the use of "slickwater" as a fracturing fluid for shale gas. In contrast to the highly viscous gels used as fractunng fluids in low-permeability reservoirs to suspend and transport sand as far as possible from the well being hydraulically fractured.

"slickwater" is water with a limited amount of sand, friction reducers and other chemical additives to improve the efficiency of hydraulic fracturing. Slickwater works well in shale gas reservoirs because its low viscosity allows the fracturing fluid to sowy leak out from the hydraulic fracture into many small, naturally occurring fractures in the shale. Additionally, the use of gelled propane in hydraulic fracturing of shale gas deposits may also prove to be beneficial.

[0102] The increased water pressure in these small fractures induces shear slip events, microseisnñc activity that can be detected only by using ultrasensitive seismorneters deployed in nearby monitoring wells. The microseismic events enhance the permeability of the shale and allow natural gas to flow more easily into the wellbore.

[0103] The locations of the microseismic events generated during slickwater hydraufic fracturing may be measured to provide operators with a picture of where the hydrofractures propagated and where the stimulation of permeability occurred. It thus reveals the approximate volume of the reservoir that is likely to be drained at any given well.

[0104] Accordingly. in. for example, shale hydraulic fracturing, horizontal well paths will be oriented according to the maximum and minimum subterranean strata stress planes at specific depths within the strata. Generally. for shale gas hydraulic fracturing, a series of four to eight fracture stimulations will be performed along a horizontal well bore.

[0105] For example, as taught by Bruner and Smosna, "the lower Barnett member contributes 75-80% of total production and the upper member. 20-25%. All pay zones must be treated for maximum economic return, and perforations typically span 200-300 ft (Kuuskraa and others, 1998). If the reservoir sections are not stacked directly on top of one another, the completion must be designed with more than one stimulation stage. Perforations should be placed in zones that are easiest to break.

that is, silica-rich shale with low clay/carbonate content and shale with naturally occurring fractures. The resulting induced fractures will have the maximum areal extent and provide more migration pathways for the hydrocarbon (Johnston, 2004b)." [0106] Accordingly, a need exists for providing a senes of horizontal wells both vertically and laterally extending from a minimum of penetrations through groundwater formations and cap rock containing toxic and incendiary hydrocarbons to provide both well integrity and increased recovery.

[0107] The upstream industry drilling and completion of wells, including the field processing of hydrocarbons prior to transportation via pipelines, tankers or other means, to the downstream hydrocarbon processing industry involves, in general, application and use of a standard set of commonly sized apparatuses for the historic challenges of the upstream hydrocarbon industry that may or may not be optimal for present and/or future subtelTanean challenges or fluids.

[0108] As described by Yergin, our world energy requirements are not merely a matter of finding energy sources, but also limiting greenhouse gas emissions, wherein efficiency gains and switches to cleaner hydrocarbon gases are necessary for the transitional switch to renewable energy sources, which are key to the survival of our present way of life.

[0109] During a transition to renewable energy sources, a need exists for efficiency gains in the drilling, completion and production of hydrocarbons as well as their environmentally sound processing, wherein toxic fluids produced and/or forming part of stimulations, e.g. slick fracture fluids, may be separated from valuable fluids prior to leaving a wellhead and disposed into a subterranean horizon below a protecting cap rock. An additional need exists for using environmental energy to process, compress and/or pump hydrocarbons in close proximity to the welihead or pipeline to reduce the carbon footpnnt or greenhouse gases associated with the infrastructure necessary for their production.

[0110] While oil is a relatively stable and easily transportable liquid product, which has allowed the hydrocarbon industry to rely on single bore wells with single flow streams, the future may be significantly different. Realizing the value of capital investment in wells targeting relatively impermeable reservoirs must address the need for greenhouse gas intensive processing of multiple flow streams of, for examp'e, gas and water to prevent the premature failure of a shale gas well or steam and oil for tar sand wells, wherein both water from shale gas and/or toxic components of tar sand production should be disposed of in deep subterranean formations far from the environment in which we live and/or water tables from which we drink.

[0111] The fluid dynamics of producing a low specific gravity gas are different from the production of a significantly higher specific gravity liquid. Various drivers for liquid production exist; including fluid production driven by a subterranean aquifcr's pressure when the fluid is lighter than water; alternatively, gases compressed by pressure and temperature into a liquid form and/or entrained in a liquid may reach a bubble point pressure and temperature that results in the transition from liquid to gas. thus reducing the specific gravity of the fluid and urging it from the well; alternatively, liquid may be urged through a well bore passing through, but isolated from, a compressed gas cap above a liquid, wherein the expansion of the gas cap downward dnves liquid upward. Gas production from, e.g., shale gas reservoirs, is simply the expansion of a compressed subterranean pressunzed gas relative to the friction of production, wherein larger diameter well bores reduce the friction of flow and increase both the rate of production and potentially the amount of recoverable reserves, subject to level of associated produced water, which may have insufficient velocity to be lifted from the larger bore and result in premature killing of the well from the weight of water.

[0112] For example, as a shale gas well is produced, the production depletes the stored pressure available until the pressure and resulting velocity of gas expansion falls below a level capable of lifting water from the well. Velocity strings may be installed to provide sufficient velocity to lift water or huff-and-puff operations may be carried out. Production continues bubbling up through any water left in the well at a decreasing rate because the friction to flow of the gas increases with the hydrostatic head of the water until the hydrostatic water column increases sufficiently to stop all production from the well. If the well is shut-in, pressure may build-up sufficiently to discharge some of the water by quickly opening the wells, after which production may continue until the hydrostatic column accumulates and stops production again, after which the process may be repeated in what is called huff-and-puff production.

[0113] Production tubing is often sized to facilitate improved liquid or gas handling, wherein huff-and-puff operations for intermediately sized tubing may be economic.

Unfortunately, while the salt cavern gas storage industry use 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 the limited forms of gas lift and jet pump arrangements.

[0114] Accordingly, the introduction of a large bore gas production flow stream with a smaller diameter dewatering stream, sized for removing residual water production or acting as a velocity string, could significantly increase both production rates and recoverable gas reserves by minimizing gas flow fnctions and dewatering the well bore using small diameter tubing assisted by capillary forces.

[0115] A need exists for large bore production and injection operation to reduce friction and improve the efficiency of gas extraction, wherein a further need exists for effectively switching production to a velocity stnng to remove produced water, prior to ultimately reverting to huff-and-puff operations.

[0116] The conventional standardization on single bore wells with single flow streams also neglects the environmental impacts numerous well bores and their effect on the immediate environment, including the impact of space occupied by surface processing facilities handling potentially toxic subterranean fluids and normally radioactive materials brought to surface. The number of penetrations of ground water horizons and other shallow water bearing formations critical to our existence and environment by numerous single bore wells, is also a serious concern. With the heightened awareness of our impact to the environment in which we live comes the recognition that not all subterranean substances brought to surface are beneficial and that each well penetrating ground water and fluid communicable formations represents a risk of spreading subterranean contaminants. Accordingly the reduction in the number of wells through upper formations can significantly reduce the risk to our environment.

[01171 For example, because shale is relatively impermeable, over millions of years gas migrating through more permeable formations and natural vertical fractures was trapped in the shale below a cap rock seal. Modern shale gas wells are those where sufficient gas was trapped to form an extractiNe deposit if the shale is fractured open and sand is forced into and props open the fractures to provide permeability.

[01181 Recent shale gas advances in fracturing technology have rightly or wrongly received blame for contaminated ground water formations, wherein it is perceived that the fracturing provided a passageway for gas to enter the ground water system. Shale is however, by its very nature, relatively impermeable and, as a result, trapped the gas from migrating, hence it is unreasonable to assume that fractures of, e.g., 100 feet or metres. at depths of 6000-ft or 1750 metres could possibly have reached ground formations, which are generally less than 500 feet or 175 metres. Accordingly, despite urban legends. it is not the fracturing of the shale that creates the problem.

but rather gas percolation around the well bore to the ground water formations [0119] Presently, there are no conventional solutions for reducing the number of well bores through the ground water system and maintaining or increasing production within the upstream oil and gas industry because the state-of-the-art is built on standardization. It is, however, possible to selectively change certain standard sizes and procedures to meet the physical constraints of the problems faced by the upstream industry without significant retooling, which in itself causes increases in greenhouse gas emissions.

[0120] Woridwide growth in the free market system and general rise of living conditions, particularly in the Far East, has generally increased the demand for most raw materials, including energy, necessary for industrial and residential development.

Changes in consumption levels of energy worldwide are presently and will continue to drive the development of non-conventional energy sources, e.g. shale gas and tar sands. While standardization of the hydrocarbon industiy's tooling and systems has served the industiy well, it was ultimately designed for conventional hydrocarbons, which are not necessarily optimal for non-conventional hydrocarbons.

[0121] A need exists for apparatus and method usable with both conventional and unconventional hydrocarbon wells to provide larger and higher pressure wellheads to increase the depth that larger bore conduits may be safely placed against overburden and hydrostatic pressures within the subterranean strata by supporting the shell of conduits within other conduits and the downhole mixing of reactive fluids to form gelatinous mixtures capable of preventing or inhibiting the initiation of strata fractures.

[0122] A further need exists for well site processing of produced and injected fluids, for example, fracturing fluids first injected then extracted during well construction or produced hydrocarbon liquids, gases and water.

[0123] Accordingly, a need exists for environmentally sensitive and efficient drilling, completion and production well design necessary to exploit subterranean deposits, e.g. hydrocarbons used during any transition to renewables located in conventional and unconventional subterranean deposits, such as impermeable shale reservoirs or tar sands, wherein the value produced fluids and associated toxic fluids are managed effectively and where possible, returning said toxic produced fluids back to the subterranean strata below a containing cap rock.

[0124] Various aspects of the present invention address at least some of these needs.

SUMMARY

[0125] Preferred embodiments provide apparatus and method for a well conduit system (1) with large diameter higher pressure conduit containment, comprising concentrically placed first (2) and at least second (3) conduits with continuous elastically compressible outer and expandable inner pipe body (4) circumferences from which a plurality of radial loading surfaces (5, 6, 41, 42, 49, 123) extend across at least a portion of and radially from at least one of said circumferences of at least one of said first and at least second conduits through at least one concentric annubr space (7) between said conduits to engage said plurality of radial loading surfaces to an associated loading surface and circumference.

[01261 Preferred embodiments abut one of said conduits to another to form a greater effective wall thickness (9) by compressing the effective diameter of said radial loading surface greater than the effective diameter of an associated loading surface and circumference, which may be expanded, prior to adjoining and consequently abutting said radial loading surfaces to share hoop stress resistances (8) between said first and at least second conduits with said abutment to form said greater effective wall thickness (9) capable of bearing higher pressures than said conduits could independently bear.

[0127] In use, preferred embodiments, control fluid communication between injectable and producible strata of one or more well passageways extending from at least one wellhead assembly (10) secured to the upper end of said first and at least second conduits to said strata through exits at the lower end of said first and at least second conduits.

[0128] Preferred embodiments may 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 large bore conduits 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 second large diameter conduit.

[0129] Various preferred embodiments may use radial loading surfaces comprising part of at least one compressible outer and expandable inner pipe body circumferences (4), for example, those depicted in Figures 7, 13, 18-20, 34-37, 50-61, and/or independent bearings intermediate to compressible outer and expandaNe inner pipe body circumferences, for example, those shown in Figures 9-12, 21-28, 30-31 and 33.

[0130] Other preferred embodiments may use radial loading surfaces comprising a partially plastic deformable portion, for example, those described in Figures 12, 12A, 13 and 18-20, and/or an elastically expandable portion to provide abutment and share hoop stress resistances (8) between first and at least second conduits. Any form of deformable material is usable, for example metal, elastomers, swellahle materials, to support the abutment of radial loading surfaces dunng or after installation.

[0131] As a plurality of second conduits (3) are inserted within the first conduit (2), hoop stresses support naturally increases with the adjoined conduits sharing loads through abutted thading surfaces (5, 6), thus causing increasing difficuldy in the expansion andlor compression of effective diameters and pipe body circumferences for placement of subsequent second conduits (3), hence the use of partially and plastically deformable loading surface that retain a portion of the shared hoop stress elasticity sharing of the pipe body through the remaining portion of the loading surfaces may result and efficiency of the effective wall thickness below 100%, but still significantly improve bearing capacity of the system (1) with each successive second conduit (3) and associated loading surfaces. The addition of plastically deformable materials, for example malleable metals, dastomers and/or sweflable materials limiting deformation of metal loading surfaces, 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 system (1).

[0132] Preferred large diameter high pressure conduit system embodiments, through their size and pressure rating, may incorporate virtually any technology developed for the smaller diameter high pressure axially concentric or axially autonomous conduits, for example, dual bore trees engaged to a dual bore wellhead to provide dual well bores. Additionally, using inventions of the present inventor, a plurality of said high pressure wells may be constructed, produced and/or injected through simultaneously within the higher pressure bearing walls of a arge diameter high pressure conduit system single main bore.

[0133] Preferred embodiments minimize the need to deviate from conventional standardization, for example, the introduction of large diameter high-pressure conduit systems does not require the removal of the rotary table for drilling operations, albeit it may need to be temporarily removed for placement of conduits and large apparatuses then replaced for drilling. Significant efficiencies may be realized if. for example. the conventional restriction of passing conduits and equipment larger than a standard size rotary table through the ng 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.

[0134] If, for example, the master bushings of a 49 /2" rotary table are removed, a conventional rig may have sufficient room to place a 36" to 42" outside diameter conduit or apparatus, depending on rig design, using its derrick, drawworks and blocks. However, if the substructure of the rig is modified, the placing of much largcr conduits and apparatuses, for cxamplc 72", 66", 60", 54" and 48" effective outside diameters, may become more efficient using the drawworks to lift and lower blocks, suspending conduits using its derrick, wherein such an adapted 49 1/2" rotary may be easily replaced within an associated adapted rotary table.

[0135] Other efficiency improvements may inv&ve use of prior art large bore bit arrangements with the necessary pump capacity to provide sufficient velocities for drill cuttings removal during boring and placement of large diameter high pressure conduit systems, or managed pressure dnlling inventions of the present inventor may be used to carry and cement large bore conduits with internal drill strings as describe in Figure 6. Preferred embodiments may be used effectively without drastic changes to the standardized apparatuses dominating the industry and prior art, primarily designed for smaller single concentric bore conduit well designs.

[0136] Preferred large diameter high-pressure conduit systems may be used to provide additiond conduit strings necessary to, for example, construct wells in veiy deep water, where fracture gradients are very low, and very deep wells, where larger bores may be needed retain hole diameters for later use of the industry preferred reservoir hole size of 8 1⁄2 inches. Various preferred embodiments may be used to provide a plurality of lower end 8 1⁄2 inch well bores into a reservoir or subterranean deposit through a single bore high pressure conduit, which may also be usable to, for example, provide a subterranean vertical separator to process produced and/or injected fluids.

[0137] Other preferred embodiments may adjoin first (2) and at least second (3) conduits using: gravity forces, mechanica' (38). pneumatic (39) and/or hydraufic (40) forces, for example, those depicted in Figures 27-32; forces such as physically hammering or pushing one into the other with mechanical, pneumatic andlor hydraulic forces, for example. those illustrated in Figures 21-26.33.50-54, 60-6!, 84-106 and 113- 123; andlor by using hydraulic forces, for example, those shown in Figures 34-36, 50-54, 60-61, 84-106 and 113-123; to cause expansion and compression of effective loading surface diameters.

[0138] Various preferred embodiments may also comprise a welthead assembly (10), for examp'e, those 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 second (18) conduit head subassemblies associated with and secured to the upper end of first (2) and at least second (3) conduits. The one or more spools (14) subassembly may be engaged at the upper end of the first and at least second conduits or between the first and at least second conduit head subassemblies to form the wellhead assembly.

Such wellheads may be the preferred embodiments shown or prior art weltheads adapted for indusion in the preferred well conduit system.

[0139] Various other preferred embodiments may comprise substantially concentric (35), axially autonomous (34) and/or transitions between concentric and axia'ly autonomous (47) conduits, for examp'e, those 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 preferred embodiment of conduit transitions between concentric and axially autonomous (47) passageways may mininrize fluid friction and erosion fluid flowing forces with their diameters and gradual anguhr transition. for example those shown in Figures 106-108, or their angular transition may occur within a shorter axial distance if fluid flowing forces and/or erosion aie less significant, for those shown in Figures 109-112.

[0140] Preferred axially concentric (35) and axially autonomous (34) embodiments of the present invention may be used for any simultaneous flow stream application, for examp'e larger bore conduits may be initially be used for production until water production causes a switch to higher velocity annular flow or axially autonomous flow velocities to provide the ability to switch between maximum production and velocity production conduits, or, for example, to aflow coflection within a tank (13), injection, andlor processing and re-use, of fracturing fluids used during well construction.

[0141] Related preferred embodiments (49) may use a plurality of concurrently weight set mechanical and/or hydraulically axially urged engagable and axially parallel associated axially autonomous conduit (34) snap connectors with elastically compressible outer and expandable inner 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) as shown in Figures 50- 54, 58-61, 76-105, 113-118 and 122-125.

[0142] Other preferred embodiments may comprised of autonomous or connecting inner passageways, annular passageways and/or ateral (194) passageways, for example, those shown in Figures 34-36, 50-54, 60-75. 84-86 and 93-105, for controlling fluid communication.

[0143] Still other preferred embodiments may comprise one or more manifold crossovers (20), for example, those depicted in Figures 62-75, 84-86 and 93-105, chamber junctions (21) and/or side-pocket whipstock (48), for example those illustrated in Figures 14-15, 17, 17A, 38, 45-49, 55-61, 76-81, 87-118 and 120-132, between at least one welthead assembly (10) and injectable and producible strata of one or more wells to selectively control apparatus placement and fluid communication using any arrangement of valves (24) and/or diverting apparatuses (25), for example. those shown in Figures! 6-7, 14, 17, 60-61, 65-68, 73-75. 93-105, 119, 1 19A-l 19E, 122- 123 and 128-132, which may be selectively placed within one or more passageways or through a welihead and inner passageway using a bore selector (32) and/or kick-over tool (33K) to control apparatus and fluid communication through said manifold crossovers and chamber junctions.

[0144] Various related preferred embodiments provide 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 bore being usable for urging a strata passage and hanging a protective metal fining 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 said conduit at an axial inclination, wherein the axis of said autonomous bore is axially and laterally offset from the through passage (198) of said conduit such that the upper end of said autonomous bore is below the upper end of said conduit and engagable with a kick-over tool to access said autonomous bore from said through passageway, as illustrated in Figures 113-118 and 120-132.

[0145] Other various related preferred embodiments bore selector tool (32) and/or kick-over tool (33K), for example those illustrated in Figures 122-124 and 128-132, to selectively access the exit bores of said chamber junction to place valves (24) and/or diverting apparatuses (25) comprising a and a plurality of wells.

[0146] Still other various related embodiment provide a kick-over tool (33K) comprising a tool for placing or retrieving well equipment via a thiough passage (198) of a conduit adjacent to said side pocket whipstock lateral bore (199), said kick-over tool comprising an elongate body (197) with an arm (195) movable with said body.

axially rotatable from a pivot point (196) on said elongate body, or combinations thereof, between a first, running and retrieving position, and a second position for using said arm to place or retneve equipment to and from the lateral bore of said side pocket whipstock by placing and retrieving said kick-over tool in the first position and using the second position to engage the upper end of said elongate body proximally to said lateral bore so as to divert said equipment to and from said lateral bore with said movable arm as illustrated in Figures 113-118 and 120-132.

[0147] Various preferred embodiments may comprise at least one boring assembly axial lower end (45) and/or axial and lateral whip-stock (46, 48) orifice exist from substantially concentric (35) or axially autonomous (34) conduits for boring strata and placing conduits within said strata and well conduit system, for example, those shown in Figures 87-90, and 120-132, [0148] Other various preferred embodiments may comprise a subterranean fluid processing tank (13), for example, those illustrated in Figures 17, 60-61 and 93-105, which may be formed within and between said wellhead and the lower end of said first and at least second conduit so as to surround and fluidly communicate with one or more well passageways.

[0149] Various related preferred embodiments may comprise a subterranean separator with connecting substantially concentric or axially autonomous conduit walls and passageways foiming inlets (26), chimneys 27), downcomers 28), diverters (29), spreaders (30) and/or mist extractors (31), e.g., those illustrated in Figures i7 and 62-68, to separate water, liquid and gas hydrocarbons, to perform fluid processing.

[0150] Other related preferred embodiments may comprise a heat exchanger (12) with substantially concentric or axially autonomous conduit walls exchanging heat between fluid within conduits and fluid within said tank to perform fluid processing [0151] Various preferred embodiments may divide or commingle simultaneous fluid flow streams through autonomous or connecting well passageways within first and at least second conduits at various depths to process or separate fluids for injection or production.

[0152] Other related preferred embodiments may comprise selective control of simultaneous flow streams, for example, Figures 17, 38, 45-48, 60-132 and 135-140, using one or more of valves (24) or diverting apparatuses (25) placed within autonomous or connecting passageways.

[0153] Preferred subterranean large diameter high pressure well conduit system embodiments may 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, wherein fluids brought 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, for example, contaminated water, within a subterranean injection horizon.

[01541 Inclusion of larger, thicker walled conduits with an increased effective wall thickness and pressure bearing integrity using embodiments of the present invention also provide greater resistance to colTosion and erosion to improve pressure and fluid well integrity.

[01551 Various preferred embodiments may comprise conduits and associated apparatuses engaged with connections using friction, welding, mandrels, dogs, receptacles, slots, slips, threads, bolts, clamps and/or hoop stress resistances. For example, Figures 50- 54, 60-61, 93-105, 119A-119E and 120-132 illustrate embodiments that use a combination of these connector types, but any suitable prior art or conventional connector may be used.

[0156] Various other prefelTed embodiments may use metal-to-metal, elastomeric and/or cement sealing of fluid communication passageways and engagement of conduits and associated apparatuses, for example, those shown in Figures 5-7, 14-15, 18-28, 30-31, 33-37 and Fig. 50-54.

[0157] Other preferred embodiments may use single or double olive compression fittings (41, 42) to secure and seal two components of said wefihead assembly together or to seal and secure two conduits together or to a component of the wefihead assemNy.

[0158] Preferred embodiments may provide a single well bore penetration for multiple wells, wherein 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, for example, minimise the risk of leaks that may contaminate ground water formations and/or to minimise surface equipment in favour of vegetation to minimize the carbon foot print or greenhouse gas emissions associated with constructing wells andlor infrastructure arid producing multiple wells.

[0159] Other preferred embodiments 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 welihead assembly (10), for example, those shown in Figures 5-7. 14-17, 38-39 and 45-49.

[0160] Larger diameter, high-pressure conduit system preferred embodiments may provide significantly more options for additional casing or linings by providing more subterranean space within higher pressure liners than is conventionally possible.

[0161] Preferred embodiments may also 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 conventionally desired hole sizes may be used with bore selectors in chamber junctions or with kick-over tools within drilling side-track pocket exit adaptations of a chamber junction for drilling, lining and subsequent access to. for example. perforate, hydraulically fracture strata and place proppants, including the cleaning of the bore after fractunng operations using conventional means or with conduits of the system.

[0162] Larger diameter well conduit system preferred embodiments may provide more conduit placement options and the option of 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 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 prefelTed well bore size and/or allow longer horizontals.

[0163] Large diameter high pressure well conduit system preferred embodiments may allow, for example, the use of the same drilling BHA on more than one wells, 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.

[0164] Large diameter high pressure well conduit system preferred embodiments may also be used to hold a reserve 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 arge diameter holes than small diameter holes at the same loss rates. The loss of bore hole cleaning velocity is not present in prefelTed embodiments because drilling fluid or mud may be stored within what is effectively a large cylindrical tank of the system which has 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 when it is used as a separator and/or heat exchanger after completion of the well.

[0165] Preferred embodiments may also use gravity assisted cementation of large diameter high pressure conduit systems after or during boring of strata and placement of protective linings to provide better cement placement, which lowers the risks of losses to the weak subterranean formations preventing the placement of good cement.

[0166] Various preferred embodiments may provide a plurality of wells vertically and/or laterally oriented and spaced to, for example. provide improved recoveiy of subterranean deposits.

[0167] Various other preferred embodiments may provide a conduit system for hydraulically fracturing strata for one or more wells individually or simultaneously to, e.g., provide improved recoveiy of subterranean deposits.

[0168] Still other preferred embodiments may comprise external compression fluid communication between a wellliead assembly and injectable and producible strata andlor between a wellhead assembly and conduits exporting fluids from one or more wells, e.g., those illustrated in Figures 135-137.

[0169] Other preferred embodiments may sdectively control fluid communication with computer operation (102, 108) of valves using electrical, pneumatic andlor hydraulic motors and connections also usable for observation of pressures, temperatures and flow-rates associated with one or more passageways.

[0170] Various preferred large diameter high pressure well conduit system embodiments 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 or provide subterranean thermally efficient processing spaces that may be computer managed (102, 108) to optimize reservoir pressure maintenance against production.

[0171] Large diameter high pressure conduit system embodiments may use subterranean data gathering and control devices that are 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, for example.

produced water, may be injected back into the strata immediately after being produced to, for example, help maintain reservoir pressures.

[0172] Various other preferred embodiments of the present well conduit system may comprise using the first and at least second conduits as part a processing installation structure (44) housing one or more well passageways extending from at least one wellhead, wherein Figures 135, 135 and 136 provide examples.

[0173] Preferred embodiments provide simple low-cost improvements applicable to most subterranean well construction and production operations that are far from obvious to the compartmentalized distinct silos of drilling, completion and well site production processing practioners, apparatuses and methods representing the present state-of-the-art because the space provided by a larger diameter higher pressure well conduit system can be used to place virtually any off-the-shelf conventional or prior art apparatus within a contained environment, separate from the environment in which we five.

[0174] Preferred embodiments may also provide additional benefit through the multiple 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 conduit to lift produced fluids, for examp'e, water, which may retard production in later years through a larger bore.

[0175] Large bore high pressure well conduit system preferred embodiments may also be constructed and operated in a more environmentally conscious manner than is currently the conventional, thus providing benefit during any transition from hydrocarbon to renewable energy sources.

BRIEF DESCRIPTION OF THE DRAWINGS

[0176] Preferred embodiments of the invention are described bdow by way of example only, with reference to the accompanying drawings, in which: [0177] Figures 1 to 4 illustrate drilling rig well operations usable with the high pressure large bore wellhead system of Figure 5, having hoop stress resistant engaged large diameter conduits.

[0178] Figures 6 to 8, 14 and i5 depict well operations usable with the present invention to place and cement subterranean conduits with, for example, the large diameter conduit hoop stress resistant engagements illustrated in Figures 9 to 13.

[0179] Figure l4A depicts a prior art plumbing compression olive arrangement in reference to Figure 14 and 18-33, while Figure 16 shows a prior art vertical separator.

[0180] Figure 17 illustrates a large bore high pressure well conduit system flow diagram depicting the interaction of fluid processing, compression or pumping and the use of computer control (108). while Figure 17B provides a dual well design and Figure 17A shows a processing arrangement example.

[0181] Figures 18 to 37 depict various large bore high pressure well conduit system arangernents of the present invention, [0182] Figures 38 to 47 illustrate comparisons of conventional practice and various method embodiments of the present invention to unconventional shale gas deposits.

[0183] Figures 48 and 49 show vanous method embodiments of the present invention to other unconventional hydrocarbon deposits.

[0184] Figures 50 to 54 depict a high pressure wellhead embodiment of the present invention.

[0185] Figures 55 to 59 depict various high pressure large bore arrangements relative to access through a single main bore.

[0186] Figures 60 and 61 shows a top down perspective view of high pressure large bore well conduit system with a vertical subterranean separator illustrating the assembled components of Figures 66 to 92 and assembled elevation views of Figures 93 to lOS.

[0187] Figures 62 to 65 illustrate vanous subterranean separator inlet embodiments.

[0188] Figures 106 to 125 depict various adaptations of chamber junction, diverter apparatus and kick-over tool embodiments usable with large bore high pressure well conduit systems of the present invention.

[0189] Figures 126 to i32 show a well bore side pocket, side-tracking and kick-over tool embodiments usable with large bore high pressure well conduit systems of the present invention.

[0190] Figures 133 to i39 illustrate various environmental energy processing systems usable with large bore high pressure well conduit systems of the present invention.

[0191] Embodiments of the present invention are described below with reference to the listed Figures.

DETAILED DESCRIPTION OF THE EMBODIMENTS

[0192] Before explaining selected embodiments of the present invention in detail, it is to be understood that the present invention is not limited to the particular embodiments described herein and that the present invention can be practiced or carried out in various ways.

[0193] Referring now to Figures 1, 2, 3 and 4, depicting 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 Al-Al, an onshore prior art coiled tubing drilling (SiB) 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 (SIC) rig (51) above a line A4-A4, respectively, wherein any rig, including those depicted (51), are usable to operate andlor drill within a large diameter high pressure conduit system (1), but wherein larger hoisting capacity rigs (SIA and SIC) are. generally. preferred for installing said conduit system (1) if said ngs are adapted for installing large diameter conduits. Various rigs, specially designed for installation of large conductors or, for example, driving or boring, placing and cementing large diameter piles, are also usable for instafling a large diameter high pressure (LDI-IP) conduit system (1).

[0194] Various embodiments of the present invention may be used in place of general embodiment representations (lAX, lAY, 1AZ and 1BA), wherein, for example, an embodiment below line Al-Al may drill one or more directional well bores for placement of conduits below a LDHP conduit system (lAX) using, e.g., adaptations of the whipstock and kick-over tool embodiments in Figures 113 to 132 or the concentric conduits embodiment of Figure 5. Such kick-over tools (33K) of the present invention or bore selectors (32) of the present inventor may be used, e.g.. to dnll a lateral extending bore as shown below line A2-A2 from a LDHP conduit system (I AY). Cable deployed apparatuses, e.g., arrangements taught by UK Patent GB2465478B, maybe operated within a LDHP conduit system (1AZ) to, e.g., clean out included separators like those depicted in Figures 17A, 60-61 and 93-98 or drill lateral bores through whip-stocks like those shown in Figures 113-132. Within an offshore environment, e.g.. a LDI-IP conduit system (1 BA) may have a subsea tree 53) located below sea level 54) at the upper end of the LDHP conduit system (1) and connected via a pipeline conduit to a platform (52) with various forms of one or more wells placed through the single main bore within the strata (A4-A4) and below the LDFIP conduit system (1 BA) and mudline (57).

[0195] Figure 5 depicts a diagrammatic cross section elevation view through a high pressure large bore conduit system (1) embodiment (1A) and subterranean strata, illustrating the accessing of a desired strata formation (61) through, e.g., perforated (60) conduits (4, 59) within a first conduit (2) embodiment (2A), generally termed as a conductor conduit, may be placed below ground (56) or mudline (57) level, wherein a p'urality of conduit (3) embodiments (3A) with an associated plurality of inner radial loading surfaces (6) embodiments, comprising any elastically flexible material/shape or a partially plastically deformable material/shape with an elastically flexible portion (6A), extending from concentric (35) pipe body (4) embodiments (4A) across intermediate annulus (7) embodiments (7A), to contact associated loading surfaces (5) embodiments (SA) by radially extending from said pipe body to abut to the adjoining conduit to share hoop stresses and form a greater effective wall thickness (9).

[0196] The wefihead (10) may, e.g.. be comprised of a smaller (IOAI) within a larger (10A2) wellhead for hanging associated concentric (35) conventional conduits 59) and pipe body embodiments (4A) extending axially downward arid substantially below said ground (56) or mudline (57) level with associated arinuli (7, 58) accessible through said wellhead (10) to said desired strata formation (61) to produce or inject fluids between said perforations (60) and wellhead (10).

[0197] Depending upon the downhole conditions and application, tubing packers, subsurface safety valves, liners, and liner top packers may also be present, wherein any appropriate conventional completion apparatus may be included within a LDHP conduit system (I) since conventional sized conduits may be used within.

[0198] The LDHP weH conduit system (IA) may, for example, be used to fluidly access significantly deeper formations (61) for ultra-high pressure and temperature applications than is presently the convention or practice because a significantly greater number of conduit strings may be used to sequentially isolate ever deeper subterranean formations, wherein an upper larger diameter wellhead (10A2) may have a significantly larger effective wail thickness (9) and associated higher pressure beanng capacity to support, for example, a smaller diameter high pressure inner conduit (59). annuli and associated wellhead (IOAI) arrangement. For example, conduits without loading surfaces may comprise an inner most 2 7/8" and 11.5 pound per foot (ppf) 95 thousand psi (lcsi) yield strength tubing conduit (59A) capable of bearing 24,630-pounds-per-square-inch (psi) collapse and 25,440-psi burst pressures. within a 5" 23.2-ppf lSOksi casing conduit (59B) capable of bearing 25.940-psi collapse and 25,100-psi burst, within a 7" 41-ppf 150ks1 casing conduit 59C) capable of beanng 23,160-psi collapse and 22,120-psi burst, within a 9 5/8" 7i.8-ppf i50ksi casing conduit (59D) capable of bearing 19,625-psi collapse and 20,450-psi burst, within a 7" 41-ppf i5Oksi casing capable of bearing 23,160-psi collapse and 22,120-psi burst, within a 95/8" 71.8-ppf lSOksi casing conduit (59D) capable of bearing 19,625-psi collapse and 20,450-psi burst, within a radial loading surface suppored II 3⁄4" conduit (4A1), 13 3/8" conduit (4A2), 16" conduit (4A3), 20" conduit (4A4) and 24" conduit (4A5), wherein a 55% efficiency of an effective wall thickness (9) of, e.g., 11 3⁄4" 60-ppf, 10.772" intcrnal diamctcr conduit (4A1) and outermost conduit 24" outside diameter (OD) conduit (4A5) comprising 55% of nominal 6.614" wall thickness, or 3.6377", capable of bearing 20,575-psi collapse and 21,219-psi burst, according to a API bulletin 5C3 calculation, thus resulting in a 20.000-psi burst rating throughout the conduits, annuli and smaller wellhead (IOAI).

[0199] A arge diameter high pressure conduit system (1), generally, expands and compresses the circumferences of larger diameter conduits, e.g., those greater than 8 5/8" OD and 7 3/8" inside diameter (ID) relative to conventionally sized conduits, to form a series of adjoined conduits with abutted loading surfaces comprising a radial extending surface and/or the circumference of the inner or outer pipe body to form an abutment hoop stress sharing reinforced conduit system surrounding smaller diameter conduits that are, generally, better able to bear pressures given the more rigid nature of the smaller diameter hoop stress bearing capability. 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 expand and compress the adjoined conduits, thus allowing stresses to pass through the abutment as shown in Figures 11 to 13. A LDHP conduit system (1) may comprise housing one or more wells and associated conduits comprising fluid communication conduits and/or well processing conduits with, e.g., computer controlled (108) compressors and/or pumps as described in Figure 17.

[0200] Referring now to Figure 6, showing an elevation diagrammatic view of slice through a subsea casing boring placement embodiment and subterranean strata from, for example, a floating drill ship or semisubmersible, showing placement of the outermost conduit (2) of a large diameter high pressure conduit system (I) embodiment (1B) comprising drilling a strata bore (66) below mudline (57) with a BRA (65) comprising a boring bit (71) and hole openers (72) integrated with drill pipe 73) between upper (62) and lower (63) slurry passageway tools, taught by UK Patent Application GB1021787.5, for placing a first conduit (2) with a loading surface (5) embodiment (SB). consisting of the inside circumference of the pipe body (4), engaged to a subsea (54) guide base (64) comprising part of the first conduit head subassembly (17) embodiment (i7B). The first conduit (2) is 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 is circulated downward (67) and returned upward (68, 69) to remove drill cuttings or strata debris from the bore (66). Once the first conduit (2) and guide base (64) are placed at the desired depth, an actuation tool, e.g. 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 BRA (65), drill string (73), upper (62) and lower (63) slurry passageway tools may be removed.

[0201] The first conduit (2) of the present invention may also be installed by any means, for example, rotation and casing drilling of the conduit (2) with any type of ng, hammering or driving of the conduit (2) into mudline (57) or ground evel (56) with any type of large hammer, or vacuum sucking of the conduit (2) into the mudline with any type suction pile apparatus and method.

[0202] Figure 7 illustrates a diagrammatic elevation slice through the subterranean strata and a LDHP conduit system (1) subsea (54) and mudline (57) or ground level (56) installation of a second conduit (3) embodiment (3C) within a first conduit (2) embodiment (2C) and cementing of the arrangement within the wefihead (10) first assembly embodiment (1OC) with a first conduit head subassembly (17) embodiment (17C) and at least second conduit head subassembly (18) embodiment (18C) with associated lower end conduits (2, 3) of a large diameter high pressure conduit (1) embodiment (IC), wherein Figure 8 shows a diagrammatic plan view of the loading surface (6) embodiments (6C) and circulation and lateral conduit (194) cementing (194C) tool flow paths (70). After placement of the first conduit (2), the second conduit (3) with spherical loading surfaces (6C) extending through the intermediate annulus 17C) may 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) to share hoop stress resistance through their abutment. In this instance, 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 thwer end through upward circulation (68), which may also 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).

[0203] The expansion of the larger effective diameter loading surfaces (6) of the inner conduit (3) within the smaller diameter loading surface (5) of the outer conduit (2) may occur with the axially downward force of the string (3, 73, 74, 75, 76), which may also 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 thading surface (SC) until the wellhead (1 OC) bnds on the upper end of the first conduit (2). Portions of the spherical abutment-loading surface (6C) may plastically deform during the loading provided the elastic hoop stresses of the conduit (3) are retained for sharing through the remaining elastic portion of the abutment (for an example see Figure 13).

[0204] As described within the teachings of UK Patent Application GB1021787.5, cementing of the second conduit (3) within the first (2) may be accomplished with an actuating tool (78) pumped through the 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 (SC. 6C) with pump force and gravity past, for example.

any fluid thief zone (77) with displaced fluid returned through the slurry passageway tool vertical passageways (82). While gravity cementing is preferable and comparable to top-up convenfional cement jobs used to bypass shallow weak formations with potential fluid theft zones (77), wherein normal conventional cement placement occurs through the centre of the string with displaced fluids and cement returned through the weaker annulus, any form of cementing appropriate to the downhole conditions may be used with the present invention.

[0205] Referring now to Figures 9, 10 and Ii, 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 with line D, respectively, of a large diameter high pressure conduit system (i) embodiment (ID), showing a concentrically p'aced second (3) conduit with a first (2) conduit with continuous elastically compressible outer and expandable inner pipe body (4) circumference loading surface (5) embodiments (SD) with 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 thading surface circumferences (SD), thus abutting one conduit to the other, wherein the effective diameter of said radial loading surfaces 6D) is greater than the effective diameter of said associated loading surface circumferences (SD) prior to adjoining them by weighted wedging, hydraulic piston driving, hammering.

rotating and/or any other means of forcing one into the other, to elastically expand and compress the pipe body (4) diameters and associated loading surfaces and abut at least one second conduit (3) into a first conduit to, in use, share hoop stress resistances (8) within this embodiment (SD) to form a greater effective wail thickness (9) capable of bearing higher pressures than said conduits (2, 3) could independently bear. In this embodiment (1D), the radial extending surfaces are ball bearings held by an intermediate concentric centralizing structure (83D) engaged around the outside diameter of the at least second conduit (3) before its placement within the first conduit (2) or another different surrounding second conduit.

[0206] Figures 12 and 12A show a sliced plan view and diagrammatic plan cross section view of the loading surface portion, of a large diameter high pressure conduit system (I) embodiments (1EI) and (1E2), respectively, illustrating an example of an additional second conduit (3E2) installed within a second conduit (3El) which has abeady been installed within a first conduit (2E). or alternatively second conduits (3E1 and 3E2) with an intermediate centralizing structure (83E1 or 83E2) insta'led together as a unit with a first conduit (2E) with loading surface 16E3). The intermediate concentric centralizing structure or strapping (83Ei) may comprise machine pressed circumferential concentric conduit plates (85) deformed over corresponding orifices and loading surfaces (6El) prior to riveting (84) the conduit plates together as shown in the arrangement of Figure 12 or wherein an alternate centralizing structure (83E2) that comprises a metal and sweflaHe material (84 and 85, respectively, or vice versa) arrangement, as shown in Figure 12A, is placed between an adjoined second (3El) and at least another second (3E2) conduit to abut the circumferential loading surface (5) embodiments (5E1, 5E2) of the conduit bodies (4E1, 4E2) against the intermediate spherical (6E1) or expanded metal (6E2) loading surfaces (6) to share hoop stresses (8. 8E1 or 8E2) after placement and form a greater effective wall thickness (9).

[0207] The illustrated centralizing structure (83E1) may be replaced with expanded metal arrangement (83E2), or any other variation loading surface arrangement, to engage circumference loading surfaces (5, 5El, 5E2) before or during installation, for example, loading surface (6E1) may be a combination of ball bearings 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, for examp'e, weight. hammering or a hydraulic piston insta'lation within the larger second conduit (3El) or the first conduit 2E) through a loading surface (6E3) if, for example, the second conduits (3E1, 3E2) are installed together as a unit.

[0208] Since the sequential installation of loading surfaces and sharing of hoop stresses increases the containing conduits resistance to expansion and/or compression, variations of conventional conduits may be used, for example, the two second conduits (3E1, 3E2) may be installed as a unit with an intermediate loading surface arrangement like that shown in (83E1) of Figure 12 or that shown in (83E2) of Figure 12A, wherein encapsulated orifice arrangements (86) contain a fluid to initiate an expansion of, for example, swellable elastomeric material, or open to provide space for a metal to compress. For example, the metal may be (85) with the elastomer being (84), or vice versa, such that at least a portion of the hoop stresses (8E2) may be shared.

[02091 The shape of the loading surfaces (6), for example the interface (6E2), 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 beanng capability by successively adjoining conduit body (4) walls and loading surfaces (5, 6) to share a portion of the effective wall thickness (9).

[0210] To provide improved adjoining of conduits and abutment of loading surfaces during the various means of installation, for example when one conduit is violently hammered into another, a centralizing structure, for example (83D of Figures 9-11, 83E1 and 83E2 of Figures 12 and 12A, 83F of Figure 13 and 831 of Figure 19) may be covered with, for example, a elastomeric substance and/or reactive swellable substance that both seal the annulus (7) between conduits (2, 3) and support loading surfaces (6) during installation. Alternatively, the annulus between conduits (2, 3) and loading surfaces (5, 6) may be, for example, cemented after installation when, for example, plastic deformation is desired (87 of Figure 13).

[0211] Figure 13 depicts a sliced plan cross section view of a portion of a large diameter high pressure conduit system (1) embodiment (IF), illustrating the sharing of hoop stresses (8) through a arger effective wall thickness (9) through the abutment of a loading surface (6F), welded (88) to the second conduit (3), against a circumferential loading surface (5) to adjoin the pipe bodies (4) of the first (2) and at least second (3) conduits, wherein a limited amount of plastic deformation (87) of the loading surface (S. 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 to increase the overall pressure bearing capacity and 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 (I), and 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, for example, a water or oil swellable material activated after placement of the second (3) within the first (2) conduit.

[02121 Referring now to Figure 14, showing an elevation view diagrammatic slice through subterranean strata and a large bore high pressure conduit system (1) embodiment (10) with a chamberjunction (21)embodiment (210). single 6live (41) embodiment (410) and double (42) olive (41) embodiment (420) arrangement, depicting boring with drill string (73) with lower end bit (71) and hole-opener (72) centralized (92) within a casing (89) or well lining (590) guided through a chamber junction (2lG) with axially autonomous conduits (34) extending axially downward from a second conduit (3G3) by a bore selector (32, 32G) and suspended with an olive (410) within a welihead spool (l4G) to provide a drilling fluid communication conduit through a tank (13) embodiment (130), holding and circulating drilling fluid similar to a trip tank, formed by the chamber junction (210) LDHP conduit system (10), [0213] Boring may proceed more conventionally with minor skidding of the rig over the exit bores (34) of the chamber junction (21G) through separate axially autonomous conduits and a welihead top similar to (lOT of Figure 54) fixed to the spool lower wellhead (100); or as depicted with drilling or boring of the strata bore (66) the drill fluid is kept within the tank by drillable cement (91) in the adjacent autonomous conduit (34), wherein once the casing (89) or well lining (59H) is released from the single olive (410), placed and cemented, it will seal the tank (130) for drilling the cement (91) and adjacent strata bore. The depicted deployment of casing (89) may be used to place and hang conduits from the autonomous conduit (34) bores of the chamber junction (21) from a central position to save the installation time of moving or skidding a rig by rotating the bore selector (32G) to access various wells conduits (34), and wherein the tank (130) may be used for improved well control of the primary fluid barrier by holding a volume of fluid that falls more slowly, due to its volume, to provide for cthsing the second barrier blowout preventers (90), if required. Circulation (93) downward through a lateral conduit (194) port (1940) in the welihead spool (140) between the casing (89) and strata bore (66), which is returned (68) with normal volumes (67), reduces the probability of the casing being stuck and better maintains the level of hydrostatic head, much like a rig trip tank.

[0214] Referring now to Figure 14 and 14A, an isometric view of a prior compression pipe fitting arrangement with a single olive (41). The tank's (130) high pressure bearing capacity is formed by the abutment of loading surfaces (6, 60) to adjacent conduits (302, 301, 2) and the securing (1501) of a large diameter high pressure wellhead (IOU) comprising a larger diameter wellhead (1001) with first (17, 170) and a plurality of second (18, 180) conduit head subassemblies with engaged conduits (2, 301-303) intermediately sealed (1601) with double olives (420) for securing and sealing the upper end conduits of the tank engaged to an upper end smaller diameter wellhead (1002). Bilderbeek and Hendrie teach the same use of a single olive (41) to secure and seal permanent conduits within a wellhead as is used within a common 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, The present invention makes a significant improvement upon Bilderbeek and 1-lendrie teachings with the use of a single 6live (410) to suspend casing (89) within a strata bore (66), such that the casing may be lowered after boring in stages to provide, for example, better circulation through weaker formations when using larger bits (71) and hole openers (72) to better facilitate improved placement of a LDI-IP 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.

[0215] Figure 15, depicts an elevation view diagrammatic slice through a large diameter high pressure conduit system (1) embodiment (Il-I) with a chamber junction (21) embodiment (210) and double (42) olive (41) embodiment 42H), illustrating how a chamber junction may be drilled in a more conventional manner, without a bore selector, with minor skidding of the rig over the exit bores (34) of the chamber junction (210) through separate axially autonomous conduits between the chamber junction and wellhead top similar to (JUT of Figure 54) secured at the upper end of the double olive (42H) securing and sealing of the conduits (2, 3) adjoined with radial loading surface (6) abutments to the circumferences of the pipe bodies. The casings (89) may be suspended from casing hangers of a wellhead 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 dnll string in a managed pressure conduit drilling arrangement of the present inventor as shown on the left hand side.

[02161 Figures 16 shows an elevation view of a cross section through a pnor art vertical separator (I I), wherein the present invention may replicate such a separator disposed downhole, with an inlet (26) engaging a diverter (129) to roughly separate entrained gas and liquid, which may fall with gravity through a downcorner (28) to engage a spreader (30) and further allow gas to be separated and migrate through a hydrocarbon liquid level (103) through a chimney (27) and mist extractor (31) to a gaseous fluid flow (97), and wherein hydrocarbons of a lighter density may separate with gravity to a level (103) for extracting a hydrocarbon substantially liquid fluid flow (98) such that heavier density water below a water level (104) migrates 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.

[02171 Figure 17 is a diagrammatic flow chart of a large diameter high pressure well conduit system embodiment (IX), depicting that the LDHP conduit system (1) may comprise first (2X) and at least second (3X) conduit bodies 4) adjoined with loading surface (5, 6) abutments to share hoop stresses (8) to form a greater effective wall thickness (9) with an efficiency greater than the conduits (2. 3) in isolation, wherein a wellhead (lOX) may 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 processing (109), which may be computer controlled (108), and wherein the pumping, compression, fluid processing and computer control may be conventionally andlor environmentally powered (110). Accordingly, the larger diameter and higher pressure bearing capability of the present invention, as compared to conventional well designs, provides significant improvements for increasing the efficiency of subterranean tanks (13), separators (ii) and heat exchangers (12) for production, injection and processing optimization of fluids from one or more wells through a single main bore, by providing accessibility, control via valves and sensors engaged with a computer monitoring and control system via conventional downhole cables and/or hydraulic lines.

[0218] Referring now to Figure I7A. a diagrammatic elevation cross section through abrge diameter high pressure conduit system (1) embodiment (11), illustrating a high pressure separator (11) embodiment (III) below a wellhead (10) embodiment (101) suitable to, for example. process a substanfially gas well from a shale gas deposit.

Gas flows (113) into the separator inlet (26) from a horizontd section (111) of the axially autonomous (34) well bores (3411, 3412), with a break line representing that the lower portion of the left well (3412) has been removed, wherein the well 3411 exits from a whipstock (461) arrangement, for example (46) of Figures 120-121, in the wall (112) of the separator (111) and gas from the shale gas deposit (110) flows through strata fractures (109) propped open with proppants, for examp'e sand.

placed through perforations (108) in the well (3411) lining or metal casing (5912) hung from the liner hanger (106) in well lining (5911) above the whipstock (461).

Wells may be formed by successively boring and hanging liners (5914), by engaging liner hangers (106) to a larger weB lining (5913), and/or, if more than one laterals from the well (3411 or 3412) is desired, a side-pocket whipstock (481), for example, the arrangements of Figures 113-132, may be used.

[0219] Production may be controlled by the subsurface safety valve (241) and travels (113) through the weB bore (3411) until it encounters the diverter (29), which, for example, may be a cable deployable plug like 25A) of Figure 1 19A, and enters the separator (111) inlet (26) where it travels upward in the chimney (37) to re-enter the well conduits (3411, 3412) to encounter a cable placeable mist extractor (31) that further knocks out liquids to the downcomer (28A) before the gas is extracted (97). As the diverter (29) and mist extractor (31) are cable deployable they may be removed for access to the lower end of the wells (3411. 3412). Gravity separation of the liquid occurs as it exits the inlet (26) and downcomer (28A) to form a liquid level (103) above a primary (28B, 30A) and secondary (28C, 30B) downcomers and spreaders, respectively, wherein if the separator (ill) stops at the lower end of the conduits (2, 3) as shown, the downcomer (28C) and spreader (30B) are omitted. In instances where a lower separator (111) pressure is desired to better facilitate drop out of liquids, the hydrocarbon outlet (98A) may be shared with the water outlet at the (28D) position of conduit (3413) to extract water, which may be injected with a pump suction from (3413) and discharge to (3414) to be disposed of within the strata until the water level (104) drops and a sensor detects hydrocarbons. wherein the pump is switched from disposal to storage until gas reaches (28D) and suction is lost, after which the pump is stopped and the separation process continues untfl a different sensor within the separator determines the pump should be restarted.

[0220] Alternatively, in a similar arrangement for a high pressure separator, liquid hydrocarbons, for example, natural gas liquids (NGLs), may also be extracted through outlet (98A) and the upper end of axially autonomous (34) conduit (3413) between the NUL level (103) and water level (104), wherein the pressure within the separator (III) may be used to force water axially down the lower end of conduit (3413) downcomer (28D), if, for example, a plug, e.g. (25A) of Figure 1 19A, is placed via a cable arrangement, e.g., (51D) of Figure 3, within a nipple in the conduit (3413) between the hydrocarbon liquid outlet (98A) and water inlet (28D).

Water entering the conduit (3413) from (28D) may, for example, be disposed of using injection into the strata through the conduit (3413) orifice (114) and annulus below the lower liner hanger (106) of a well (3412), or the conduit (3413) may be placed within its own strata bore to a desired ocation for water disposal or, e.g., water flood or reservoir pressure maintenance.

[0221] The conduits (21. 31) of the LDHP conduit system (11) of the separator (111) may extend axially downward from the wellhead (101) vertically, which is shown diagrammatically and may extend for hundreds of metres or feet, or the conduits (2,3) may extend axially downward and laterally along line (112) at incflnations and dog-leg seventies generally limited by the stiffness of placing and abutting large diameter conduits with abutted loading surfaces; albeit said loading surfaces may be adjusted to accommodate flexure at predetermined depths, while retaining a proportion or efficiency of the resulting effective wall thickness of the adjoined conduits. If the separator (iii) and conduit system (II) conduit (2, 3) extend along line (112), the downcomer (28C) and spreader (30B) allow a deeper hydrocarbon to water interface and intake (98B) of conduit (3414) may be used for hydrocarbon extraction using, e.g., the pump and sensor arrangement described above in a lower pressure separator arrangement. or, for example, (28E) of conduit (3413) is used as a water outlet to the orifice (114) for subterranean water disposal in a higher pressure separator arrangement, wherein the deeper LDHP conduit system increases volume for improved operation of the separator (Ill).

[0222] As demonstrated, the supporting axially autonomous (34) conduits (3413, 3414) may be configured in a variety of ways to interface with well bore conduits (3411, 3412) andlor producible andlor injectable fluids associated with the well bore conduits.

For example, the build-up of solids within the separator (i 11) may be removed by placing fluid communicating straddles, e.g., the straddle (25E) of Figure 1 19E may be placed in the nipple (107) across communicafion 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 (3413, 3414), wherein cable operable fluid motorized tools of the present inventor may be operated, e.g., brushes, bits and other tools deployed from the rig (5 ID) of Figure 3. within the conduits using circulation between the conduits. Additionally, the lower orifice (114) may also 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. Furthermore, ball, dart or other drop mechanism sliding side doors, spring return andJor otherwise actuated lateral port valves may be operated by dropping a ball down one conduit (e.g. 3413) and taking fluid returns through the other (e.g. 3414), wherein the actuating mechanism may be recovered by reversing flow through the associated conduits. Accordingly, any subterranean device (for example, 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 p'ugs, dropped actuation devices such as balls/darts/cylinders, dropped object actuated devices, remote controlled devices, pressure/temperature activated devices, valves, chokes, orifices, jet/velocity pumps, chemical injection apparatuses, sensors, straddles, bomb hangers and gauges) may be placed and/or operated within the separator through interfaces in the well head (101).

[0223] Figure 1 7B shows a diagrammatic plan view of the wellhead (10) embodiment (101) and bores of the LDHP conduit system (11) of Figure 17A, illustrating the arrangement of wellhead (101) interfaces that, for example, may comprise the main well bores (3411. 3412). wherein the upper end may be connected to a conventional dual bore valve tree, with the conduit system comprising a single main conduit, tank, separator (ill) and/or heat exchanger with supporting conduits (3413, 3414). Also, for example, control lines (102 of Figure 16) for valves (e.g., 241 and 100, 101 of Figure 16) may be passed through (116) the wellhead; downhole pressure, temperature andlor fluid level sensors, andior sensor cables may pass through (117) through the wellhead; downhole flow meters and/or meter cables may pass through (118) through the wellhead; and chemical injection lines may pass through the wellhead.

[0224] 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, and the embodiment of two conduits of a large diameter high pressure conduit system (1) embodiment (11) and double (42) olive (4i) embodiment (421), depicting a second conduit (3) embodiment (3J) adjoined to the first conduit (2) embodiment (21) with a loading surface (6) axial helical embodiment (61) abutted to an associated loading surface (5) embodiment (5J), with upper end wellhead (10) embodiment (lOJ), wherein the wellhead comprises the upper ends of the adjoined conduits secured and sealed with a double olive alTangement. The axial helical nature of the loading surfaces may be used to facilitate a turning or screwing abutment during placement with, 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 (I OJ) builds the strength of the wefihead with successive layers of second conduits (3) within a first conduit (2), wherein the intermediate double olive arrangement is a loading surface arrangement.

[0225] Referring now to Figure 19 and 20, illustrating magnified detail views within lines F and U 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) radially extending through the annulus (7) between conduits (2, 3) and abutted to the circumferential loading surface (5) of the first conduit (2J) to foim a larger effective wall thickness (9J2) with an upper end wellhead (101) foirned by first (17) and second (18) conduit head subassembly embodiments (ifl, 18J), wherein a double (42) olive (41) embodiment (42J) comprising two single olives (4lJl, 4212) secured and sealed between wellhead flanges (i20, 121) using a wedge (122) embodiment (1221) to form a greater wellhead effective wall thickness (911), relative to wellhead conduits that have not been adjoined and abutted with loading surfaces. The shape and slenderness of the loading surfaces (61) allows, for example, elastic andior plastic deformation or bending of the surface during placement, wherein the annulus (7) may be filled with, e.g., cement after placement or fluid reactive swellable elastomers before placement, which swell after placement, to secure the radial loading surfaces from further deformation or bending, thus securing the abutment of the loading surfaces (5, 6), and providing a percentage of the effective wall thickness (912) with installation of successive second conduits (3) within a LDHP conduit system (1) that become successively more difficult to expand with adjoined second conduits (3).

[0226] Figures 21 and 24 are plan views with section lines H-H and 1-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, double (42) olive (41) embodiments (42J) also comprised of both securing (15) and sealing (16) embodiments (ISJ) and (161), showing the sealing, secunng arrangement in a pre-engagement of the securing (l5Jl) seal (1611) position and post-engagement of the securing (1512) seal (1612) position.

[0227] Referring now to Figures 22 and 25, magnified detail views within Unes 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), wherein the upper portion of the wedge (l22JU) is urged from the installation, securing and sealing positions (122J1, 15J1, 16J1) to the installed, secured and sealed positions (122J2, 15J2, 16J2), respectivdy, 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).

[0228] Figures 23 and 26 are magnified elevation views within detail line G of Figure 18 of the double (42) olive (41) embodiment (42J) within the weithead (1OJ) in a pre-engagement, unsecured (1511) and unsealed (1 6J 1) position and a post-engagement, secured (15J2) and sealed (16J2) position. respectively, of the large diameter high pressure conduit system (1) embodiment (1J) shown in Figure 18 showing the welihead flange (121) supporting (lOIS) the double olive arrangement (42J) between the inner (121) and outer (120) welihead (101) flanges of the associated first (171) and at least second (l8J) conduit head subassemblies. As previously described, the wedge (122J) is urged downward to urge the upper (122JU) towards the lower (1221L) wedge portions to urge out the inner 141J2) and outer (41J1) olives (41) loading surfaces to abut against the loading surface circumferences (5) of the wellhead flanges (120, 121) and wedge loading surfaces (123) to adjoin the second conduit (3J) to the first conduit (2J) and form the wellhead (IOJ).

[0229] The dashed lines of Figure 26 represent an alternative wellhead (10) embodiment (1011) and double (42) olive (41) embodiment (4211), wherein the wedge may be urged axially upward or downward with, for example, a receptacle (124) for the wedge embodiment (122J) or with a i-slot (125) and/or receptacle (124) as shown in embodiment (12211) if, for example, the wellhead flanges (120, 121) extend upward to form welihead embodiment (1OJ1) flush with the upper end of the wedge (122LU), wherein the 1-slot may be used to grip and urge the wedge from its secured position if the wellhead is being disassemNed.

[0230] 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 0 associated with Figures 28 and 31, wherein Figures 28 and 31 are magnified detail views within lines M and 0, respectively, of a double (42) olive (41) embodiment (42L) also comprised of securing (15), sealing (16) embodiments (15L) and (16L) using inner (4lL2) and outer (4lLl) olives (41) loading surfaces, usable, for example, between the wellhead (1OJ) circumferential loading surfaces (5) of Figures is to 20 and wellhead (10K) of Figure 33 or (IOL) of Figures 34 to 37 when the second conduit (3L) loading surfaces (6) are below the wellhead, showing the sealing securing arrangement in a pre-engagement wedge (122L1) unsecured (l5L1) and unsealed (l6Li) position and a post-engagement wedge (122L2) secured (i5L2) and sealed (l6L2) position.

[0231] The inner (4iL2) and outer (41L1) olives (42) in unsecured and unsealed positions (41L2A, 4ILIA) are urged into secured and sealed positions (41L2B, 4ILIB) engaging their circumferential loading surfaces to the circumferential loading surfaces of the wellhead and wedge sealing profiles (123), such that the upper wedge portion (122LU) is held while the lower wedge portion (122LL) is urged between the olives (41) of the double (42) olive (41) arrangement.

[0232] Figure 28 also shows a J-slot (I 24LJ) 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 (I 22LU) while urging the lower one (1 22LL), or vice versa during removal of the double olive arrangement 42L).

[0233] Referring now to Figures 29 and 32, illustrating 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 operated by any means, e.g. hydraulic cylinders, mechanical or electrical driven gears or screw drives and/or pneumatic pistons, are inserted into the wedge receptacles (124L) and moved between positions (126A) and (I 26B) such that either the thwer (I 24LL) or upper (I 24LU) wedge portion is moved for installation or removal.

[0234] Figure 33 illustrates a magnified elevation view within detail line U of Figure 18 of a wellhead (10) embodiment (20K) with a double (42) olive (41) embodiment (42K) also comprising pre-engagement wedged (122), securing (15) and sealing (16) embodiments (122K, 15K, 16K, respectively), forming a large diameter high pressure conduit system (1) embodiment (1K), showing the inclusion of seals (127) at the lower end of the wedge (122K) alTangement, which may be urged axially downward between the wellhead (10K) flanges (120, 121) of first (17) and at least second (18) conduit head embodiment (17K, 18K), while hydraulic pressure is applied above the seals (127), wedge (122K) and support surface (IOKS) to expand the circumference loading surface (5) of the outer flange (120) and compress the circumferential (5) loading surface of the inner flange (121) so as to reduce the force required to engage the inner (41 K2) and outer (41K]) olives (41) and allow the hoop stresses of the flanges (120, 121) to better engage, secure and seal the double olive arrangement (42K) once the hydraulic pressure is released after placement.

[0235] Hydraulic driving lateral opening (194) embodiments (194K) may be present, similar to (i94L) of Figures 34 to 37, to hydraulically drive a second conduit (3) lower end piston with fluid comnmnicated through the annulus (7) between conduits (2, 3), wherein a profile support (1OKS) and seals (127) allow application of pressure between the loading surfaces (6K) and the conduits (2K, 3K) adjoined them with associated expansion and compression to allow abutting of the loading surfaces (6K) to the circumferential 5) loading surface of the first conduit (2K) and dnving of the wedge (122K) between during installation, and after which the pressure may be relieved with a plug or cap (128) sealing the hydraulic fluid piston communication lateral opening (194K).

[0236] Figure 34 depicts an isometric view with a quarter section of the outer conduit assembly (3F) removed with detail lines Q, R and P, and Figures 35, 36 and 37 are magnified detail views within the lines of Q, R and P of Figure 34 of a large diameter high pressure conduit system (1) embodiment (1L) with engaged wellhead (10) embodiment (lOL), showing how a second conduit (3L) may be hydraulically driven into a first conduit (2L), wherein if additional spoo1s (14) are added to the upper end of the wellhead (IOL), a plurality of inner second conduits may be hydraulically placed into outer second conduits. A lower end well casing (89) and lining (59L) is engaged below the pistons (130, 132) to secure and protect or case-off the strata well bore (66) to prevent unintentional strata fracture initiation or propagation and/or strata bore instability during subsequent well operations, wherein 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).

[0237] To urge the at least second conduit (3L) axially downward within the first conduit 2L) or another second conduit, if hydraulic spools, similar to the first conduit head (17) embodiment (17L), are engaged to the upper end of the welthead (1 OL) to allow hydraulic fluid to be pumped through lateral conduits (194) embodiments (194L).

which may have a selective pressure passageways (129) to various annu'ar passageways (7) for communicating with circulating piston (133) 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) secured to the first conduit head (17L), whereby the second conduit (3L) is urged axially downward within the first conduit (2L), when fluid is pumped into the lateral conduit (194L). When a second conduit (3) is urged within the first conduit (2) or a different second conduit, the hydraulic pressure expands and compresses the associated pipe bodies (4) and associated loading surfaces (5,6) to facilitate urging of one within the other such that when the hydraulic pressure is removed the radial extending loading surfaces (6L) abut to the circumferential loading surfaces (5) to share hoop stresses, form a larger effective wall thickness, and suspend one conduit within the other. A series of pistons (130. 132) maybe 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, for example, cementing (134) of the conduit being urged within the strata bore (66) through the annular passageways which have been forced below the containing conduit pipe body (4) using the shallower piston (130), still within the surrounding conduit, and wherein cementing (133) of a shallower piston's (130) annuli (7) may be performed through selective fluid ports (129) with a cementing seal [similar to (133) with selected circulation ports to match associated ports (129)].

[0238] Once placement of a second conduit's (3) radial extending loading suifaces (6L) are below the wellhead support (IOLS), which may be slotted to accommodate such loading surfaces or have a continuous circumference, the seal (i33L) may be used for cementing and/or it may be replaced with a special cementing seal, which has injection and/or return circubtion orifices and passageways through its body for cementing operations, after which the second conduit head (118) embodiment (18), shown as just the pipe body 4), may be sealed against the first conduit spool (17L) or another spool added to its upper end, wherein various pack-off and/or double olive (42) arrangements may be used to seal andJor secure the upper end of the second conduit (3) within the welihead (IOL).

[0239] Referring now to Figure 38, an elevation cross section diagrammatic view of a slice through the strata comparing large diameter high pressure conduit system (1) embodiments (IN, IM) to prior art (137, 138) well designs for an unconventional injection and production of well accessing, for example, 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 andlor leaking cap rock (1148), e.g. relatively impermeable limestone, claystone, siltstones. and shale, into a more permeable and/or naturally fractured shale stone (1142), which may also be covered by a less permeable cap rock (1143) or simply a more impermeable shale.

[0240] Commercial quantities of hydrocarbons within more conventional permeable formations may have been lost over millions of years through migration (146, 147) and leakages (148) until only unconventional shale gas deposits remain in locations where hydrocarbon devdopment has never been commercially viaNe before and/or in close proximity to, for example, cities (140) and farmlands (141), where the value of the above ground environment and ground water formations (152) may be very high and require significant protection from leakages that may occur around improperly cemented well bores, in damage areas caused by drill rig (51A) operations across many sites during well construction, and, subsequently for work-overs and abandonment. As the recovery rates for shale gas deposits are conventionally very low, e.g. 7%-l2%, the construction cost of economic shale gas wells is limited, despite close proximity to demand, and more economic solutions are required before widespread development of the deposits may occur before, e.g., cleaner burning gas may replace cheaper coal for the operating of, e.g., electrical power plants.

[02411 The present invention may be used to reduce the number of, for example, drill site locations (IN, iM) with a plurality of wells (136) from a single main well bore with LDHP conduit system (i) chamber junctions (2i) and/or a plurality of multi-lateral whipstocks (135 and 46, 48 of Figures 87-90 and 120-132), which also minimizes penetrations through the ground water system (152) compared to conventional wells (137, 138) with a single deviated or horizontal (iii) well bore, e.g. a single lateral (135) from a multi-well (136) LDHP conduit system (IM) may be used to replace a conventional well (137), generally practiced to provide pressure integrity during hydraulic fracturing (ISO). In addition to minimizing the foot print of surface equipment (1M) with, e.g. tanks, separators and heat exchangers to process production and waste fluids, e.g. mineral contaminated deep subterranean produced water, said waste fluids produced during construction and production, e.g. slick water fracturing fluids. may be re-injected through concentric or autonomous conduits of a LDHP conduit system (IN) into non-commercial subterranean formations (144) to maintain subterranean pressures and urge migration (i47) to producible formations (142).

[0242] Additionally. wells may be maintained and/or abandoned with small foot print rigs 51D), generally termed rig-less operations, to further minimise the impact to, for example, farm land (141), thus reducing environmental impact. Furthermore, the pressure integrity properties of the chamber junctions and multi-lateral whipstock embodiments of the present invention provide the same pressure integrity as a conventional well design for hydraulically fracturing (150) operations, wherein conventional multi-lateral technology does not provide the necessary access.

integrity and re-entry features, and hence batch operations may be corned out to reduce the cost of wells and improve recovery rates of shale gas using, for example, simultaneous hydraulic fractunng (150) across a plurality of wells through a single main bore and a single rig-up and rig-down of associated equipment.

[0243] Figure 39 illustrates an isometric view of a shale gas deposit strata slice, with a quarter section removed, from the sower end of a large diameter high pressure conduit system (1) embodiment (10) passing through the deposit to diagrammatically illustrate hydraulic fracturing (150) of the strata in. e.g., shale gas or tight sandstone formations; while Figure 40 illustrates a piece of shale (142), its layering (152) and a fracture orientation (77) to access a cross section of said layering, wherein fracture orientation depends upon the deposit in question and natural fracturing engagement with and 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 intended fracture, thus limiting its effectiveness to place proppants and extract fluids from a low permeability deposit. To ensure pressure integrity, conventional multi-lateral technologies are not generally used, and casing (89) lining (590) are cemented (151) within well strata bores (66), wherein the LDHP conduit system (10) allows a plurality of wells andlor lateral bores (66) from a single main bore to be cemented in place with conventional liner techn&ogy to ensure pressure integrity.

[02441 Generally, once a well bore is sealed, a lower end perforation (108A) is made and an artificial fracture (77A) is hydraulically initiated and propagated (150) with, e.g., slick water and light sand proppants or a more viscous gelled solution and larger sand proppants. depending upon the deposit characteristics, until the desired fracture length is achieved or screen-out, or plugging of the proppants occurs, and hydraulic fracturing is stopped. The under displacement of proppants, screen-out or packers may be used to isolate the lower artificial fracture (77A), and the process is 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, e.g., a near horizontal (ill), highly deviated or vertical well bore accessing a deposit. If multi-laterals (135 of Figure 38) and/or multiple well bores are vertically aligned, simultaneous hydraulic artificial fracturing may occur between vertically stacked laterals or well bores so that the fractures use the lower fluid friction, large diameter and high pressure capabilities of the conduit system (10 and e.g. lN, 1M of Figure 38) to perform multiple vertically stacked fractures, e.g. multiple lower end fractures (77A) followed by closer multiple fractures (77B). and so on and so forth, through a single main bore; thus reducing the hydraulic fracturing rig-ups (139 of Figure 38) and rig-downs, and associated surface environmental impact.

[0245] Referring now to Figures 41, 42, 43 and 44, illustrating plan, elevation and two isometric views. respecfively, of the application of a conventional well design to an unconventional shale gas deposit with conventional well spacing. similar to that taught by Bruner and Smosna and others, showing a conventional well (137) bore (66) through strata with an vertical offset from well centre of approximately 1000- 2000 metres and substantially horizontal section (111) of approximately 500-1500 metres at a depth between approximately 1000 and 4000 metres, wherein a horizontal section of approximately 735 metres with a series of artificial hydraulic fractures 77) of approximately 100-500 metres lateral wide and 25-50 metres vertical height extending from a casing, cemented and perforated lining of the strata bore (66), wherein nine wells (137) spaced approximately 915 metres in one direction and 1067 metres in the transverse direction may cover a deposit of approximately 2285 metres by 2744 metes and 25-50 metres deep. Conventionally, if vertical access to a deposit with greater than 25-50 metres of artificial fractures is required, further adjacent wells (137) must be added to land a horizontal (Ill) weB bore (66) above or below those shown, e.g., 18 wells may be required for doubling the vertical access.

[0246] Figures 45 and 46 illustrate diagrammatic elevation and isometric views of a large diameter high pressure conduit system (1) embodiment (IP) usable to access a larger vertical (153) shale gas deposit portion to increase recovery through, e.g., simultaneous vertical (153) artificial hydraulic fracturing (77). showing simultaneous fracturing (77A1, 77A2. 77A3) 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 equivalent to conventional practice. after which another vertical (153) set (77B1, 77B2, 77B3) of simullaneous artificial fractures may be initiated and propagated to place proppants and stimulate production. Additionally, waste fluids from artificially 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.

Using lateral whipstock embodiments of the present invention, bores (66) of either a lateral (135) or multi-well (136) nature may be fined and cemented in a conventional manner to provide equal pressure integrity to that of conventional single bore well designs (137). thus allowing for a plurality of wells or lateral with a single main bore and ground water formation penetration.

[0247] Referring now to Figure 47, 48 and 49, depicting diagrammatic isometric, elevation and plan views of various well trajectory and large diameter high pressure conduit system (1) embodiments (1Q), (1R) and (IS), respectively, illustrating various lateral whipstock and autonomous conduit (34) and/or side pocket whipstock (33, 33A, 33B) well bore (166) arrangements usable for shale gas deposits or other low permeability formations requiring artificial hydraulic fracturing (77) and fractures (77D) for waste fluid disposal. Lateral and autonomous (34) well bores from a single main bore conduit system (IQ. IR. IS) may extend vertically (153 of Figures 45-46) or laterally (155) to intersect, e.g., natural fractures (154) to form a fracture matrix through their intersection with artificial fractures (77) to better recover fluids from a subterranean deposit. as taught by Bruner and Smosna.

[0248] 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 large diameter high pressure conduit system (1) embodiment (1T), wellhead (10) embodiment (lOT) with snap-together connector (49) embodiment (49A) fomting part of a conduit hanger spool (14) embodiment (14T), depicting a second conduit (3) embodiment (3T2) adjoined to another second conduit (3) embodiment (3Tl) adjoined to a first conduit (2) embodiment (2T) with an abutment of loading surfaces (6) radially extending from a pipe body (4) against circumferential loading surfaces (5) of the adjacent pipe body (4) to form larger effective wall thicknesses (9) for hoop stress sharing 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) may control the pressure bearing capacity, wherein the effective thickness (9T2) may be increased, for example, by increasing the minimum wall thickness of the conduit head spool (I 8T2).

[02491 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; shown, for example, as seal rings (159A, 159B. 160A, 160B, 160C) in receptacles (163), threads (158), bolted (156) flanges (161), boiled (156) clamps (157) and snap together mandrels (49A) onto which, for example, valves, valves trees and/or other conduits apparatuses may be engaged using hoop stresses. Load shoulders (164) within the hanger spool (14T) may be used to hang, for example, production and injection conduits, wherein any means of hanging conduits, such as conventional olive arrangements. may be used.

[0250] Placement of the LDHP conduit system (IT) 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 its lower end for placement of a second conduit (3T1), which may extend bdow the lower end of a previously placed conduit (2 or 3) such that radially extending loading surfaces (6) extend to the circumference or loading surfaces of the previously placed conduit, which may be a smooth circumference or, for example, another radially extending loading surface, wherein, for example, opposite axial helical radial oading surfaces (e.g. 6J of Figure 18) are abutted together to form a relatively tortuous annulus space between conduits that when, for example, cemented or filled with a swellable material provides enhanced stress sharing, integrity and efficiency of the resulting effective wall thickness (9).

[0251] A piston may be engaged to the thwer 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 adjoin one conduit to another by expanding one and compressing the other to affect the effective loading surface diameters for placement and after which removal of the hydraulic pressure allows respective contraction and expansion to abut loading surfaces and share 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) and seal (e.g. i33 of Figures 34-37) to provide a hydraulic seal used during placement, which may or may not need removal when the casing head (l8Ti.

I 8T2) is threaded to the conduit (3T1, 3T2) to secure an inner seal (I 59A, I 59B) and landed in the previous conduit head (17, 18) to engage the outer seal (160B, 160C), which is secured with a bolted (156) claim (157).

[0252] Altematively, the weight of the a conduit (3), axially extending below a previous conduit (2, 3), may be used to place. adjoin and abut conduits. A drive head may also be secured to the conduit (3T1, 3T2) to forcibly hammer the conduit downward and to place, abut and adjoin the two conduits, after which the drive head may be removed, the casing head installed. Optionally, gravity cementing of the annulus through the lateral conduit (194, 194T1, 194T2, 194T3), or conventional cementing with return circulation through said lateral conduit, may occur.

[0253] figure 53 and 54 are isometric and exploded views of the large diameter high pressure conduit system (I) embodiment (IT) 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) and associated second (3T1) engaging another second conduit head (18) embodiment (18T2) with associated additional second conduit 3T2), wherein conduits (2T, 3T1, 3T2) are sequentially placed at ever increasing depths to form an effective wall thickness across any combination of conduits to meet the pressure bearing requirements of the conduit system to a required depth, after which one or more wells may be axially concentrically or axially autonomously (34) placed in the strata with a single bore valve tree, or a valve tree with a plurality of bores placed at its upper end, for further controlling fluid communication.

[0254] As shown in the Figure 50 plan view and Figures 53-54 isometric views of the conduit hanger spool (14) embodiment (14T). a plurality of parallel wells may be bored through the large diameter high pressure single main bore formed by the conduit system (IT). One or more wells are placeable through the concentric bore of the conduit system (iT), for example, a chamber junction and/or parallel or axially autonomous (34) well conduits passing through the example conduit hanger (14T), wherein a conduit hanger (114) may comprise any conduit hanger system supported by the first (17) and at least second (18) conduit head subassemblies, to access strata.

Optionally, the space between the single main bore of the conduit system and the one or more well conduits passing through it may be used for fluid separation. e.g. in the arrangement of Figure 17A, or heat exchanger.

[0255] In. for example, remote subsea wells like those shown in Figures 4 and 6, which may be tied back to platforms (52 of Figure 4) via a subsea pipeline, heat is important to the flow assurance of produced fluids and high water cut hydrocarbon wells may require the thermal effect of produced water to provide flow assurance as production progresses along a pipe line cooled by the ocean. in such instances, separation within the ocean environment could be detrimental due to the lost heat of removed water, The natural subterranean insulation and heat retaining properties of the sub-mudline strata may, however, be used with a LDI-IP conduit system (1) separator (11), wherein separated water of sufficiently low concentrations of hydrocarbons andlor other toxic material may be continually released to sea dunng separation such that heat is transferred during separation within the thermally insulated strata, thus forming a heat exchanger (12) within the LDHP conduit system (I). Mternatively, a pump may be added to inject separated water into the strata through a separate axially autonomous conduit well bore to form a heat exchanger (12) within the conduit system (I).

[0256] Any variation of conduit routing placeable within the main bore of the LDHP conduit system UT) from the larger diameter and smaller diameter conduit orifices of the conduit hanger (14T) and hung from load shoulders (164 of Figure 50) of the hanger or, for example, olive arrangements engaged to the hanger, may extend to fluidly producible and/or injectable subterranean strata to form autonomous wells, separators and/or heat exchangers to carry out fluid processing, with any variation of suitable control, measurement and/or pumping apparatus, engageable to the system.

being usable for said processing.

[0257] As shown and described herein, a LDHP conduit system is analogous to a blank canvas or empty pressure bearing subtelTanean tank (13) within which any manner of well construction apparatus may be placed and method may be used, wherein not only separators (11) and heat exchangers (13) are possible, but aho chamber junctions (21) and bore selectors (32) taught in GB2465478B, rotary cable tools taught in GB2471760B, managed pressure conduit strings and slurry passageway tools taught in GBi0217875, manifold strings taught in PCT US2Oii/000377 and GB 1104278.5, manifold crossovers and chamber junction crossovers taught in PCT US2Oii/000372 and GB1104280.1, and wherein any combinable conventional flow controlling devices, e.g., welihead 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, sm-face 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, venture, velocity or jet pumps, connectors, andlor seal devices are usable.

[0258] for example, manifold crossovers may include flow mixing devices, e.g., venturi or jet pumps, sliding side door or gas lift valves, chamber junction crossovers, chamber junction manifolds, a junction of wells, slurry passageway apparatuses, and/or manifold crossover embodiments with radial passageways, which can be usable through conduit stnngs to fluidly communicate between passageways, and which can be combinable with additional apparatuses for engaging or communicating with a passageway through subterranean strata, other manifold crossovers, chamber junctions, and/or one or more junctions of wells to form a fluid communication passageway of a manifold string, which can be usable with flow controlling devices to selectively control and/or separate, simultaneously flowing fluid mixture streams of varying velocity.

[0259] Where conventional practice for applications invohing apparatus, such as sliding side doors, jet pumps, frac sleeves and gas lift valves. may form simultaneously flowing fluid streams, the applications of such practices across various well types are limited; particularly by the pressure bearing capacity of the containing conduit system and available downhole space, which therefore prevents standardization of a member set of apparatus and methods usable perform simultaneous flow stream operations and develop readily available off-the-shelf applications that are coveted by well construction practitioners and operators.

[0260] Therefore, a practical need exists for apparatus and methods usable for placing a plurality of cable and tubing-conveyed subterranean valves within a large diameter high pressure containment single main bore easily accessible without repeated large scale rig-up and rig-down, or mobilization and demobilization of rigs, to contain well pressures, for an associated plurality of passageways to pressurized subterranean regions. In addition, there is a need for methods and apparatus that are usable to replace traditional surface separators with subterranean separators and other processing equipment, while retaining access to both the annulus of the single main bore used for processing and the innermost passageways of associated strings for measuring, monitoring and maintaining of the lower end of a subterranean well, including, for example, engaging replacement insert valves and/or other flow control devices usable to construct passageways and control fluid communication andJor pressures within a well.

[0261] As demonstrated in Figures 1 to 54, a large diameter high pressure conduit system (I) may be formed to house a plurality of axially concentric well bores and/or axially autonomous well bores through a wellhead (10) and system within which manifold string arrangements and manifold crossovers of the present inventor may be used with valves, flow control devices and other flow controlling andlor measurement devices and lines which are usable in various configurations and arrangements within a single LDHP main bore. One or more selectively controlled pressurized fluid mixture flow streams from one or more substantially hydrocarbon andlor substantially water wells through a single LDHP main bore, during well construction and/or operations, are further demonstrated within the remaining Figures, wherein various sizes and pluralities of wells, manifold strings, manifold crossovers and flow control apparatus arrangements may be formed with the present invention.

[0262] Figures 55, 56 and 57, show an elevation view with section lines U-U and V-V with removed portions shown by break lines along axial downward portions, 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 (I) embodiment (Hi) and loading surface high pressure chamber junction (21) embodiment (21U), illustrating an example LDHP conduit system (1) sizing, wherein a first conduit (2) 72" embodiment (2U) with internal circumferential loading surface (5) is abutted against a second conduit (3) 66" embodiment's (3U1), which is abutted against another second conduit (3) 60" embodiment's (3U2), which is abutted against still another second conduit (3) 54" embodiment's (3U3) associated radial loading surfaces (GUi, 6U2, 6U3, respectively) to adjoin the conduits (2U, 3U 1. 3U2, 3U3) and form a greater effective wall thickness (9) embodiment (9U) that is greater than the sum of the 2 1⁄4" pipe body (4) wall thicknesses.

[0263] For example, according to an API bulletin 5C3 calculation, the standard within the industry, and using 8Oksi material, a 72" conduit with a 2 1⁄4" wall thickness will bear 4375-psi burst and 1526-psi collapse, a 66" conduit with a 2 1⁄4" wall thickness will bear 4772-psi burst and 1975-psi collapse, a 60" conduit with a 2 1⁄4" wall thickness will bear 5250-psi burst and 2520-psi collapse, a 54" conduit with a 2 1⁄4" wall thickness will bear 5833-psi burst and 3186-psi collapse pressures for a conventional well design absent of abutment and hoop stress sharing.

Hypothetically, since its weight per metre could make controlled placement impossible, if the wall thickness could be combined (i.e. 2.25" x 4 = 9") to produce an equivalent ID conduit with a 67.5" outside diameter and 9" wall thickness weighing 5623 pounds per foot or 2,56 tonnes per foot or 0.78 metric tonnes per metre, capable of bearing 18,666-psi burst and 18488-psi collapse pressures, said hypothetical conduit would have less pressure bearing capacity than the installable equivalent wall thickness (9U) of the present invention with a nominal wall thickness of 11.25" (72" OD -4S.5" ID / 2) at an 86% efficiency or a 72" OD conduit with 9675" wall thickness (11.25" x 0.86), which wou'd be capaNe of bearing 18812-psi burst and 18,610-collapse pressures. according to the API Bulletin 5C3 calculation.

[0264] Accordingly, the present invention is capable of greatly exceeding a 54" conventional single main bore well design, wherein it is the general practice to design two internal unsupported concentnc conduits, and wherein the production annulus of a 54" conduit with 2.25" waIl thickness and 80-ksi material would be capable of beanng capacity 5833-psi burst and 3186-psi collapse pressures, even at unrealistically low efficiencies for an effective wall thickness (9) formed through sharing of hoop stresses and abutment of loading surfaces during sequential adjoining of conduits. Accordingly, the nature of loading surfaces (6) and annular spaces (7) may be adjusted with, for example, malleable metals, supported with swellable elastorners or cement, to design the desired wall thickness efficiency, size and number of adjoining conduits needed to meet the pressure bearing capacities as well as the final internal diameter desired for axially concentric and/or axially autonomous conduits and/or subtelTanean processing and flow control or mixing apparatuses usable with various methods to optirnise fluid communication of producible and/or injectable fluids between a welthead and the subterranean strata.

[0265] As shown in Figure 55 to 57, 24" and 9 5/8" well casing (89) and linings embodiments (59U1. 591J2. 59U3) may extend downward from the single main bore adjoined conduits (2U, 3U1, 3U2, 3U3) within which a 20" casing may be placed through the bore of the 24" casing, with a 7" casing placeable within the 9 5/8" casing bore. A 16" conduit with an integrated side-pocket whipstock (481J), similar for example, to (48E, 48F and 48G of Figures 126-132), and adjacent 7" and 3 /2" apparatus and fluid communication conduits are also shown within the 16" casing placeable within the 20" casing to, for example, form the well configurations shown in Figures 38 and 45-49 using the depicted arrangement of axially concentric (35) and axially autonomous (34) conduits within the single main bore formed by adjoining of first and second conduits (2U, 3W, 3U2, 3U3).

[0266] Referring now to Figures 58 and 59, showing an elevation view with section line W-W and break lines along axially downward conduits indicating removed sections, and a plan along line W-W. respectively, depicting a large diameter high pressure conduit system (i) embodiment (iV) and loading surface high pressure chamber junction (21) embodiment (21V) with snap-together connector (49) embodiment (49B), showing an example LDHP conduit system (I) sizing, wherein a second conduit (3) 60" embodiment's (3V3). which is abutted against another second conduit (3) 54" embodiment's (3V2) with 2 1⁄4" wall pipe body (4) wall thicknesses which is abutted against still another second conduit (3) 48" embodiment's (3V1) 1" pipe body (4) wall thickness and associated radial loading surfaces (5, 6V1. 6Y2, 6V3, respectively) to adjoin the conduits (3Vl. 3V2, 3V) and form a greater effective wall thickness (9) embodiment (9V). wherein further second conduits (3) may also be place within a first conduit.

[0267] The arrangement provides an 18 3⁄4" ID axially autonomous (34) conduits usable for axially concentric (35) conduit placement of, for example those of a conventional well sizing of 13 3/8" OD casing with a 12.347" ID, 9 5/8" OD casing with a 8.535" ID, and 7" OD casing with 6.004" ID. Such casings may be conventionally hung with liner hangers (106 of Figure 17A) within the 18 3/4" (59V2, 59V4) ID extending from and placed with the 48" pipe body OD chamber junction (2 lv) as, for example, 20" casings (89), together with supporting 9 5/8" casings (89, 59Vl, 59V3), usable for cementing, circulation andior as independent well bores to, for example, inject and dispose of waste fluids within the strata, wherein an alTangement embodiment (49B) of hydraulically actuated snap together hoop stress connectors (49) may be used to run axially autonomous (34) conduits simuhaneously.

[0268] Sealable hydraulic ports (166) forming part of the connectors @9) and arrangement 149B) may be used simultaneously to operate the snap together the connections, for example as taught by Morgan et. al. and Gallagher et. al. as part of the simultaneous connection embodiment (49B) of the present invention, which is not obvious to practioners or an industry almost totally reliant on screw couple connectors who rarely use snap together connections, wherein embodiments of the present invention snap together a plural of connectors simultaneously as part of a axially an circumferentially autonomous (34) for a plurality of wells, e.g. embodiment (IV), and/or subterranean processing system requiring sealing beyond those of the snap connectors with, for example. seal stacks and polished bore receptacles.

[0269] Figures 57 and 59 also show optional central single bore accesses (165) of 18 3⁄4" and 21 3⁄4" diameters to suit various sizes of risers and blowout preventers (BOPs, 90 of Figure 14) using, for example a chamber junction and bore selector, as depicted in Figures 60-61, 76-81 and 93-105, using a hanger spooi (14) with a corresponding orifice, or, alternatively, a hanger spool (14) with a plurality of access orifices, for example (14T of Figures 50-54). Manifold and chamber junction crossovers described in Figures 62 to 75 are also usable to transition from axially concentric (35) to axially autonomous (34) conduit fluid and apparatus communication, for example, between the central bore access (165) bore and the axially downward disposed bores (e.g. 59U1, 59U2, 59U3, 59Vl. 59V2, 59V3, 59V4).

[0270] Referring now to Figures 60 and 61, illustrating 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, with the vertical scale skewed from the lateral scale to provide a view of the long a large diameter high pressure conduit system (1) embodiment (lY) shown across Figures 94-105, forming a subterranean tank (13) embodiment (l3Y) with internal components comprising a subterranean separator (11) embodiment (II Y) 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) embodiment (2lZl, 2lZ2 and 21Z3) with snap-together connector (49) embodiments (49C. 49D, 49E, 49F, 49G) anangement, associated with Figures 93 to 105 and component parts shown in Figures 66 to 92, wherein the fluids of a plurality of wells through the single main bore may be both accessed and processed together or independently downhole using a plurality of barriers to the environment and simultaneous flow streams.

[0271] Referring now Figures 34-39 and 45-49, depicting LDI-IP conduit systems that may use, for example, axially and circumferentially (34) autonomous conduits placed substantially parallel through the inside diameter of a LDHP conduit system (1) hung from and accessed through one or more orifices in a wellhead hanger spool (14), e.g. Figures 1-5, 14-17, 17A and 17B. 50-54, or a single bore access to a plurality of wells passing through a LDHP conduit system (1), e.g. Figures 60-105, which may use manifold crossovers and chamber junction crossover taught in PCT US2Oii/000372 and GB 1104280.1, that may be adapted to provide access, tool and fluid communication, and wherein all of the embodiments of the present invention may use simultaneous flow streams of varying velocity taught by PCT US2Oii/000377 and GB1104278.5 within a tank (13) formable with a LDHP conduit system (1) and usable as a separator (11) and/or heat exchanger (12).

[0272] In Figure 60 and 61. various large diameter high pressure conduits (3. 3Y I) may be adjoined with LDHP conduit assemblies (3Y2) placed with, for example, a central conduit access chamber junction (2iZi, 21Z2 and 21Z3. also shown in Figures 76-Si) engaged together with snap connector autonomous conduit (34) embodiments (49E, 49F. 490) to upper end axially and circumferential autonomous conduit (34) bundles (34Y, also shown in Figures 82-83) with corresponding snap together embodiments (490) to provide a centralized conduit access for urging subterranean bores axially downward using drill strings, casing strings (187, 186, 185, 182) and various other apparatuses, e.g. liner hangers (167, l67A, 167B, 167C) and concentric bore (35) polished bore receptacles (PBR. 168), after which the well may completed with, e.g., seal stacks (169) inserted into PBR's (168) connected to manifold crossovers (20Z, 20Y), or e.g. production tubing hung from a spool (14T of Figures 50-54) if parallel autonomous bores (34) without central assess manifold crossovers (20).

[02731 A senes of axially and circumferentially autonomous conduit (34) bundles (34X) may be engaged with hoop stress connections, e.g. snap together connections 149C), which may be engaged (49D) to a LDHP chamber junction (2lZl and 3Y2), also shown in Figures 87-90. within a first conduit or one or more other LDI-IP second conduits (3Y1). Well construction may proceed in a conventional manner through one or more orifices in a wellhead (10) and conduit hanger spool (14) with or without a chamber junction, as shown in Figures 5, 14, 15, 17 and 50-54, or a central access system with, e.g. manifold crossovers (20) and further chamber junctions (21), as shown in Figures 60-105.

[0274] Well casings (182. 185, 186, 187) maybe hung within the conduit bundles (34X) with liner hangers (167, 167A, 167B, 167C) so that annulus access orifices (189, 190, 191), which may be closed with straddle packers (e.g. 15E of Figure il9E) allowing axial access of conduit (188) through a centre passageway within the straddle or left open to fluidly access annuli under the liner hangers to perform cementing operations and/or monitor annuli pressures. Alternatively, casings may be hung one inside the other, e.g. (186) hung in (187), (185) hung in (186) and (182) hung in (185), or hung concentrically within each other from the conduit hanger spool (14) of the wellhead. wherein the concentric conduits (182, 185. 186. 187) may also have axially extending loading surfaces (6) to abut one to another to share hoop stresses and form a larger effective wall thickness, and wherein one or more axially autonomous (34) groups (182, 185, 186, 187) of conduits effectively form one or more heat exchanger (11) tubes within the tanlc (13) formed between the one or more axially and circumferentially autonomous conduits (34) single conduits (188) or said groups of conduits, the inside diameter of the LDHP conduit system (1), the welihead at its upper end and packer (167) or chamber junction (21) bottom at its lower end.

[0275] Configuring or crossing over (e.g. 182 to an upper end annulus flow passageway) of axially and circumferentially autonomous (34) well bores (59Y2) comprising axially concentric (35) well bore flow conduits (182, 185, 186, 187) fluid and apparatus access andlor processing using, for example, the apparatuses of Figures 60 to 105 is described herein, it must be stressed that axially and circumferentially autonomous 134) well bores of concentnc 35) conduits may simply be disposed in an axially parallel configuration through the single main bore of the LDHP conduit system (1), for example (3411 and 3412 of Figure 17A) and (well bore 59Y1 or conduit 188 of Figure 60) dependent upon the well application and need. For example, where onshore rig (S1A of Figure 1) daily costs may be less than offshore rigs (51C), the additional costs of moving a BOP (90 of Figure 14) between axially autonomous (34) well orifices in a conduit hanger spool (14), for example (14T of Figures 50-54, may be more cost effective than the arrangement described in Figures 60-1 05, wherein operations through a subsea tree (53) with an offshore rig (5 IC), where a plurality of bore valve tree arrangements are significantly more complex. may favour single central access through the valve tree with subterranean selection of bores for fluid and apparatus communication, for example, the arrangement of Figures 60-105.

[0276] For central well bore access systems, 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) plugs (25A of Figure 1 19A) is described within the following paragraph to address the needs of offshore installations and subterranean deposits, however the preferred apparatus and method for most wells may be simply to provide a plurality of axially autonomous (34) well bores and valves trees with a plurality of bores or a plurality of valves trees, potentially stacked vertically or arranged as horizontal trees for each of axially autonomous (34) wells within the inside diameter of a LDHP conduit system (I).

[0277] Sliding side doors, valve side pocket mandrels andlor any other prior art or conventional method or apparatus may be applied to each well to exchange fluids between any particular weB bore and the tank (13) formed by the LDI-IP conduit system (1) through which they pass.. Any manner of control or data acquisition may be placed about or within conduits in the tank to allow manual or computer monitonng 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 (13) of the system (1), which through various annulus access mechanisms may access the tank, wherein the tanks plurality of walls (2, 3) act as primary and secondary high pressure barriers for subterranean processing. Well entry into the tank (13Y) from the lower end may be secured and sealed with various conventional methods, such as packers (167), polished bore receptacles (168) and seal stacks (169).

[0278] 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 (1 1Y) 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 production. fluid access to the tank (i3Y) 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 (13), 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).

[0279] A central access system of chamber junctions and/or manifold crossovers and manifold strings, are usable during drilling or completion and production, or they may be installed for one and removed for another. For example. 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, e.g. a side pocket drilling whipstock with kick-over arrangement, where for example drilling and completion on one or more wells may occur vertically, and wherein one or more aterals is kicked off from the main bore using a side pocket drilling and liner hanger mandrel and kick-over tool access.

[0280] 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 diverter plate (29) embodiment (20W), illustrating how the flow (i7i, 173, 174) through conduits (59W1, 59W2. 59W3) may be diverted with a diverting device, e.g. 25A of Figure 11 9A, placed in a nipple (172) to divert intemal flow (171) to the tank (13), while crossing over annulus flow (173) and allowing other annulus flow to pass through (174) the manifold crossover (20W), wherein a sleeve nipple (i75) may be used to cover a crossover port and stop flow (173) from an annuus from crossing over. If control valves or other apparatus are located below the crossover (20W) they may be connected to lower (176) passageway entries and exit upper (177) passageways communicating, for example, hydraulic control line fluid, wherein 3 separate upper passageway exits (177) with associated lower entries are shown.

[0281] Referring now to Figure 65, a diagrammatic elevation view of a large diameter high pressure conduit system (1) embodiment (lAB) with a three flow stream adapted manifold crossover (20) separator inlet (26) and diverter plate (29) embodiment 20AA), depicting a similar flow streams arrangement to that of (20Y) shown in Figures 66 to 68, illustrating how the outermost annular flow stream (174) may be diverted to the tank (13). heat exchanger (12) or separator (ii) through an inlet (26) to engage a diverter (29), used to resist for example erosion, while inner flow streams (171 and 173) are crossover over at various points and diverting devices (25), e.g. (25E) of Figure 119E, are used to close tank (13) or separator (12) inlets (26) through the passageway of concentric (35) conduits (179, 180, 181).

[0282] 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 (25). e.g. (25A) of Figure 1 19A, which transition from smaller diameters to larger diameters, as shown in the upper and lower break lines and around (178) straddle nipples (175) and diverting devices (25), to control flow velocities and minimize erosion, wherein, as shown in Figure 65. plugs and straddles may be placed to selectively control the flow of fluids through the manifold crossover into the tank, separator or heat exchanger, and wherein removal of various flow diverting devices causing crossover, well bore access through the inner most bore may be carried out using, for example. cable deployed apparatuses. The flow control crossover is further shown within the LDHP conduit system (1Y) across Figures 94 and 95.

[0283] Referring now to Figures 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 (2lY) of the present inventor, illustrating how axially autonomous (34) conduits (182, i83, 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) is maintained through the chamber junction (21Y) and the use of a bore selector, wherein the chamber junction fluid crossover manifold is 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. unless one or more of the plugs is removed during flow.

[0284] Figures 73, 74 and 75. a p'an 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 confinuation of the lower end of Figure 74, showing a simultaneous flow manifold crossover (20) embodiment (20Z) of the present inventor, showing how three subsurface safety valves (24) may be arranged such that the flow within the flow within each of the passageways is controlled by one of safety valves with flow crossing over at each flow diverting apparatus (25, e.g. 25A o Figure 1 19A), which may be removed to allows access through the central passageway to axially autonomous passageways (e.g. 182, 183, 184 of Figures 69-72) of a chamber junction crossover (e.g. 2iY of Figures 69-72). Passageways within and between the conduits (179, 180, 181) may be enlarged (178) to account for fluid velocities and potential erosion where necessary. or a constant diameter may be maintained (178X) if velocity and erosion is not problematic. Similar to Figure 65, except with subsurface safety valves (24) where the outlets (26) are shown, each of the flow streams may be controlled with individual safety valves (24Z1. 24Z2. 24Z3) and associated control lines (200), also shown in Figure 96, wherein the control lines may also bundled (200B) into a multi-line umbilical, as shown in Figure 95.

[0285] 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 the outlet (26) and diverter (29). control line feed through (176) axially upward until it is adjacent to the hydraulic control line (200) of the intermediate valve 24Z2) which also extends upward until they enter two way manifold crossover (20Z2) contr& line feed through (176A. l76B) and continue axially upward to become parallel with the third safety valve (24Z1) control line (200) from the upper control line connection (176C), after which all three control lines progress with the conduits to pass through the welthead and allow remote control of each of the safety valves from surface. Hydraulic control fines (200).

fibre optic cables, electrical cables, sensor lines, or any other small conduit, computer operated cable, wire or similar apparatus may be passed through the various subterranean components as shown to provide the necessary information and control for subterranean processing.

[0286] Cabling and/or controls may also be tied back to another conduit with a wet connector. Wet connectors may provide ports within a pressure vessel with a relatively area, and are used for example in remote operated vehicles (ROVs) and underwater cameras within pressurized ocean environments and well bores, or the conduits or tank of the present invention, wherein they are also wet-mateable, or capable of being connected in a fluid environment. For example, wet connections may be placed within an axially autonomous conduit (e.g. 188 of Figure 60-61) during installation, after which a connector and trailing wire may be pumped down the conduit to and plug into the wet connector. An apparatus with a trailing umbilical cable may be pumped down a conduit within the LDHP conduit system, for example cameras, cutting devices, or gauges to engage a wet connector to, for example, remove the need to pass hydraulic control cables through various apparatus (176, 176A, 176B), or perform any other function necessary to downhole fluid production and/or injection processing under subterranean pressure and temperature conditions.

[0287] Referring now to Figures 76 and 77, a plan view with line AC-AC and an isometric cross section along line AC-AC of Figure 76 of a loading surface high pressure chamber junction (21) embodiment (2lZi) 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) may be simultaneously coup'ed, or snapped together via hoop stress connectors.

[0288] Figures 78 and 79 show a plan view with line AD-AD and an isometric cross section along line AD-AD of Figure 78 of a loading surface high pressure chamber junction upper end (2i) embodiment (2lZ2) with upper end snap-together connector (49) and PBR (207) embodiment (49F). showing a lower end mating seal stack mandrel (206) and snap connector (49) simultaneously conduits connector embodiment 149E) engagable to the upper end of Figure 77.

[0289] Referring now to Figures 80 and 81, a plan view with line AE-AE and an isometric cross section along line AE-AE of Figure 80 of a loading surface high pressure chamber junction upper end (21) embodiment (21 Z3) with upper end snap-together connector (49) and PBR (207) embodiment (49G) engageable the lower end of Figure 83, showing a showing a lower end mating seal stack mandrel (208) and snap connector (49) simultaneously conduits connector embodiment (49F) engagable to the upper end of Figure 79.

[0290] Figures 82 and 83, a plan view with line AF-AF and an isometric cross section along line AF-AF of Figure 82 of a loading surface high pressure fluid axially autonomous conduits 34) arrangement embodiment (34Y) with upper end snap-together connector (49) and PBR (207) embodiment (49G) engageable the lower end of other axially autonomous conduit arrangements (34Y), showing a showing a lower end mating seal stack mandrel (209) and snap connector (49) simultaneously conduits connector embodiment (49G) engagable to the upper end of Figure 8 1.

[0291] Referring now to Figures 84, 85, 86 and 86A, a plan view with fine 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 an axially autonomous conduits (34) and manifold crossover (20) arrangement embodiment (34Z) with snap-together connector (49) embodiment (49D), illustrating 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) one opposite ends of profiled nipple conduits (175), usable for engaging diverting devices. eg valves. straddles and plugs, at opposite ends of a ported (223) conduit (215) engagable with a lateral passageway (217) 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 and box (213) connectors at the lower end. Additional conduit wall thickness (219) may be placed around the larger and lower hoop stress resistant larger diameter conduits to match the pressure bearing capacity of the smaller diameter conduits at the crossover point.

[0292] For snap together connections (49), a simultaneous connection bracket embodiment (229) combining a larger diameter engaging mandrel (225) for engaging the receptacles of a larger diameter box connector (211) and pin connector (210) receptacles (226) and small diameter engaging mandrel (227) for engaging a smaller diameter box connector (213) and pin connector (212) receptacles (228), is usable to ensure that the inaccessible side of the snap together boxes (211, 213) are simultaneously clamped and coordinated with the clamping machine used on the accessible side to snap boxes (211, 213) expanded with hydraulic pressure onto associated pins (210, 212) compressed with the same hydraulic pressure applied through ports (166) during the process of simultaneously supplying hydraulic pressure to and clamping the six well bore conduits (59Y1-59Y6) to engage boxes to pins, after which hydraulic pressure is released and the profiles and hoop stresses of the connectors (210-213) secure associated conduits together. Any arrangement of hydraulic hoses and/or clamping mechanisms may be used to operating the plurality of snap together connections (49, 49D) of the present invention.

[0293] The arrangement (34Z) may also be cover with, for example. a large diameter second conduit (3) with loading surfaces (6) for abutting and adjoining 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 and conduits.

[0294] figures 87 and 88, an isometric view with detail line AH and magnified detail view within line AH of Figure 87, of an axially autonomous conduits (34) embodiment (34X) with an axial lower end (45) and lateral whip-stock (46) orifice exit embodiment (46Y) with snap-together connector (49) embodiment 49D), depicting larger diameter well conduits (231) and smaller diameter well conduit (232) between the chamberjunction and whipstock.

[0295] Referring now to Figures 89, 90, 91 and 92, a plan view with line Al-Al, an elevation cross section view along line Al-Al with break lines represent removed portions and detail fines AJ and AK, a magnified detail view with line AJ and a magnified detail view with line AK, respectively, of the lateral axially autonomous conduits (34) embodiment (34X) and whipstock (46) embodiment (46Y) with 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 and box (212) and pin (213) smaller diameter pin connectors with associated brackets (229) for simultaneous connection.

[0296] An upper (229U) bracket (229) where large diameter engagement (225, 226), wherein the engagements (227, 228) are not axially aligned and the smaller diameter and the and lower (229L) bracket (229), wherein they are approximately aligned, secures the upper box connectors (210, 212) so that they may be snapped into the lower pin connectors (211, 213) secured together with the lower bracket (229L).

using a clamping machine engaged to the outwardly exposed receptacles (226, 228) of the boxes (210, 212) and pins (211, 213) 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. Pressure injected into the centre port (l66A, 166D) is forced between the connector pins and boxes to exist ports (166B, l66C. 166E, 166F) adjacent to metal to metal upper (234) and lower (235) nose seals axially supported by associated upper (237) and lower (236) adjacent load shoulders. Once placed, positioned the hydraulic pressure is released from the ports (166), which may be plugged to stop intrusion of undesired fluids and/or leakage of the hydraulic oil used for expansion and as an anti-corrosive fluid, the box and pin portions of the hoop stress connector snap together to engage teeth (233) which when combined with hoop stresses prevent separation of the connection.

[0297] In comparison, where the first (2) and second (3) conduits of the present invention use the friction of an axial length of loading surface abutment and hoop stresses to prevent movement, and wherein olive and dual olive arrangement use the containing hoop stresses against a shorter axial frictional length of two smooth surfaces, hoop stress connectors use engagement teeth with a unique pattem to ensure that the connectors are fully engaged, i.e. the pattern is such that mated connectors have a fixed distance, typically shoulder-to-shoulder engagement, between the pin and box shoulders, and associated hoop stresses of the box's loading surfaces abutted to the pin's loading surfaces ensure that the connecting teeth do not separate. Also, while the snap together connections taught by Gallagher et. al. are described herein for their ability to quickly be assembled, any suitable connection of a non-rotating nature, 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 provided a plurality of axially autonomous connections can be made within the necessary time frame for well construction, are usable.

[0298] With regard to welding in a controlled environment and in the field, material compatibilities may require threaded connections between pipe bodies and connectors, e.g. across 1 1O-ksi and 52-ksi material. In many instances, welding (230) of the various conduits and connectors within a controlled and heat treated environment is preferred cost effective method of constructing axially autonomous (34) conduits bunifie (34X. 34Y, 34Z), manifold crossover (20) and chamber junction (21) embodiments of a LDHP conduit system (1), but any suitable connection method is acceptable, e.g. clamped or bolted flanges.

[0299] Hoop stress snap together connections may have burst, collapse and axial loading capabilities greater than the conduits to which they are fixed to, hence it is important to ensure a good connection between the connectors and pipe body, wherein, when possible. welded (230) connections are prefelTed. Additionally, the effective wall thickness of snap connectors may be downsized when included within a LDHP conduit system (1) first (2) and second (3) conduits, to better facilitate installation, since the connector does not need to bear hoop stresses independently and may gain strength from sulTounding conduits, hence snap connectors may be used more for their axial bearing capacity, sealing and installation than burst and collapse rating.

[0300] When snap connectors are used on first (2) andlor second (3) conduit embodiments, they may have loading surfaces matching the loading surfaces of the conduits on which they are welded (230) to ensure axial continuity of the loading surfaces, resultthg abutments and effective wall thicknesses of the present invention, If threaded connections are used for first (2) and at least second (3) conduit embodiments any of the various means of placing a loading surfaces over the connectors, which may have an upset or may be flush, e.g. profiled or flush clamping, pinning, bolting or field welding, may be used for placing loading surfaces over the conduit connection.

[0301] As demonstrated in figures 76 to 92, the claimed simultaneous connection of a plurality of axially and circumferentially autonomous (34) well bores (59Y 1, 59Y3, 59Y5) and axially autonomous (34) well bores (59Y2, 59Y4, 59Y6) which may share circumferences during chamber junction transitions (21Z1), such that the conduits (182, 185, 186, 187), conduit hangers (l67A, 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 within the plurality of simultaneous'y 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), could not be obvious to practioners accustomed to single concentric bore weB designs, and hence simultaneous coupling of autonomous conduits (34) are taught herein.

[0302] Figure 93 is a plan view with line AL-AL and 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 and so forth, to the upper end of Figure 105 which is a continuation of the lower end of Figure 104, of the large diameter high pressure conduit system (1) embodiment (1Y) with a subtelTanean tank (13) embodiment (13Y) with an internal subterranean vertical separator (I 1) embodiment (1 IY), heat exchanger (12) embodiment (12Y), manifold crossover (20) embodiment (21Y, 2iZ), manifold crossover chamber junction (21) embodiment (21Z) and loading surface high pressure chamber junction (21) embodiment (2iZi, 2iZ2, 21Z3) arrangement of the snap-together connector assemNed (49) embodiment (49D, 49E, 49F, 49G) component parts of Figures 66 to 92 and associated with the orthographic tilted isometric views of Figures 60 and 61, illustrating adjoined second conduit (3) embodiments (3Y1, 3Y2, 3Y3) with loading sm-faces (6) abutted to circumferential loading surfaces (5) having intermediate annuli (7) to form a greater effective wall thickness (9) embodiment (9Y), usable as a subtelTanean separator (II), heat exchanger (12) andior tank (13).

[0303] Subterranean bores are formed and first and second (3, 3Y1, 3Y2, 3Y3) conduits are placed and a LDHP chamber junction (21, 21Z1, 21Z2, 21Z3) and autonomous conduit bundles (34Y) may be placed and a bore sdector (e.g. 25D of Figure ii 9D) is used to access and place further conduits (187, 186, 185) wherein the lower end of each successive conduit is placed deeper. A screwed box (238) and pin (1239) rotary connector may be used for ease of connecting first and second (3, 3Y2) conduits as they may be installed individually, or snap connectors or other suitable connections may be used if first and second conduits are installed together, e.g. a described in Figures 12 and 12A. A cementing shoe may be added to the lower pin (239) end of second conduit (3Y2).

[0304] Below the whipstock (46) assembly (46Y) A subterranean bore may be formed and conduit (187) may be placed and secured to well bore conduit (231) of a conduit bundle (34X) with a liner hanger (167) assembly (167A) and cemented in place using the lateral passageway (217) manifold crossover between smaller conduit (232) of well bore (59Y1) and larger conduit (231) of well bore (59Y4) which form part of conduit bundle (34Z), or suing the lower end of conduit (232) of the whipstock assembly (46Y), or by conventionally cementing around the liner hanger (167). The process may then be repeated for conduit (186) and liner hanger (167B), and conduit (i85) and liner hanger (167C), each of which may be hung within the conduits of the autonomous conduit assemblies (34X, 34Y, 34Z) forming well bores (59Y2, 59Y4, 59Y6). When a cross over passageway (217) is not being used it may be covered with a straddle (e.g. similar to. 25E of I 19E) engaged in nipple profiles (175).

[0305] 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 the autonomous well bores (59Y1, 59Y3, 59Y3) may be used as separate wells usable with liner hangers (167), PBRs (i68) and/or other downhole boring and casing or lining equipment to, for example, inject fluids for waste disposal or water flood, or produce fluids from the subterranean strata, or provide access to an associated tank (13) or separator (12), or convey cables, apparatuses, cameras or other apparatuses used within a subterranean environment for well construction, production, intervention, safety, integrity, maintenance and/or abandonment.

[0306] After boring and casing or lining the well bores (59Y1-59Y6), the wells may be completed by placing a fluid communication conduit for injection andlor production (182) with lower end tail pipe and mandrel (169) engagable with 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 as shown 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 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.

[0307] A valve rnanif&d 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) are used to crossover flow within the manifold (20Z), which may be removed to access p'ugs (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 fines may be bundled into an umbilical (120DB) which are extended to suiface for monitoring and control of the safety valves and/or other subterranean equipment having control lines within the umbilical. Control lines and umbilical bundles of cables and conduits may also terminate in subterranean wet connections that are engaged by p'acing a cable connection, e.g. by pumping against a piston on its sower end, from surface to the wet connector.

[0308] 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 1 19C or 25C of figure 199C) maybe used to divert flow to a separator inlet (26) and diverer (29) usable for erosional protection of the ported (240) central well bore (59Y7) access to the tank (13), fluid separator (11) andlor heat exchanger (12) annulus.

During well construction, the ports (240) may be covered with, for example, a wear bushing or left open if access to the tank is desired to store, for example, drilling fluids.

[0309] The lower end of the tank (13) may be fluidly accessed with, for example, a ported subassembly (241) having nipple profiles (175) engagable with a straddle (e.g. 25E of Figure 11 9E) 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 (112) may be cleaned, for example, 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 gravity settled to the bottom of the tank.

Ported assemblies (241) may be added along the axis of well bores for various reasons, including, for example, as an hydrocarbon outlet (98 of Figure 16), wherein valves may be inserted during installation with a drilling rig (51A of Figure 1, SIC of Figure 4), or subsequendy using a caNe or wirel inc rig (51 D 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 computers to control processing (108 of Figure 17).

[0310] As demonstrated by the example central access well configuration in Figures 60- 105, a plurality of wells may be place from a central access within a single main bore, however it should be understood that this example is one of a various ways to construct a subterranean well, wherein the application of a LDHP conduit system (1) using manifold crossovers and chamber junctions may be practiced other than as specifically described herein, and wherein a plurality of wells, manifold junctions and chamber junctions are not a required feature of the present invention, as described in Figure 5, and wherein substantially parallel circumferentially and axially autonomous well bores may be passed through the single main bore of a LDI-IP conduit system (I) 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 fluid communicate producible and injectable fluids from the subterranean strata, for example a lower end chamber junction is not necessarily required for a plurality of wells through the single main bore of a LDHP conduit system (I), since the lower end may be cemented closed or left open to use fracture gradient of the surrounding strata for pressure relief of the annulus about the plurality of wells, or single well.

[0311] Referring now to Figures 106 and 107, upper and lower isometric views respectively ofalarge diameter high pressure conduit system (I) embodiment (IAC), shown as a dashed line, of an axially concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47A), showing how a smooth transition may be used to reduce the erosional friction simultaneous fluid flow stream velocities, wherein the transition (47) is may not necessarily be a manifold crossover (20) or chamber junction (21), since the crossover of flow may not be 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, they are not circumferentially autonomous as the inside diameters transition from being autonomous to being concentric and hence have a shared circumference.

[0312] Figure 108, a plan view with dashed lines showing hidden surfaces of a large diameter high pressure conduit system (1) embodiment (lAD), shown as a dashed line, with concentric (35) and axially autonomous (34) transitional conduit (47) embodiment 47B) variation of (47C) of Figures 109-110 with a 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. (25B) of Figure 1 19B. lower end mandrel (243 of Figure 1 19B) may be inserted and oriented in a bore selector extension receptacle (242) to fluidly and mechanically access the autonomous bores (34). Example sizes are shown to demonstrate that the arrangement (47B flow transition, 21AA chamber junction) may be used within embodiments (1U) and (IV) of Figures 55-57 and 58-59.

[0313] Referring now to Figures 109 and 110, isometric and elevation views, respectively, of a large diameter high pressure conduit system (1) embodiment (1AE), shown as a dashed line, with concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47C) similar to the sized transition (47B) of Figures 108, showing an instance 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, wherein a bore selector extension receptacle (242), similar to that of Figure 108, is usable to onent a bore selector (32) and diverter (e.g. 25B of Figure 1 19B) to divert fluids and apparatus to and from lower end autonomous conduits (34).

[0314] Figures III and 112 show elevation and plan views, respectively, of a large diameter high pressure conduit system (I) embodiment (lAP), shown as a dashed line, with concentric (35) and axially autonomous (34) transitional conduit (47) embodiment (47D) of a side-pocket whipstock (48) embodiment (48A), depicting two 16" conduits offset by 4", to provide a bore with vertical access similar to any conventional well, wherein the amalgamation of both bores is placeable within a 20" ID and usable 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), wherein the entire assembly may be cemented in place and after which one vertical and one or more latera' well bores may be drilled and lined.

[0315] It is presumed that the conventional practice of standardization across all wells, the lower power ratings of historic boring apparatuses, the cost and ability to manufacture large bore thick casings, and the limitation of conventional 24" 52-ksi casing with a wall thickness of 1.5" capaNe to bear more than 5687-psi burst and 5842-psi collapse pressures, according to API Bulletin 5C3, has prevented the use of side pocket whipstock, e.g. the embodiment (48A). However, with the present higher power boring arrangements and as unconventional hydrocarbons, i.e. those that are not easily accessed at a low unit cost, become ever more important to world energy, as taught by Yergin, the standards on which the hydrocarbon industry was built may change.

[0316] Accordingly a LDHP conduit system (1) with a more conventional well size may use, for example a 24" 52-ksi conduit with a 1.5" wall thickness conduit abutted to a 30" 52-ksi 1.5" wall thickness conduit with loading surfaces that span the annulus between the conduits and which are supported to provide at least an 80% efficiency of adjoined effective wall thickness or 3.6" = [0.8 x (30"-21")!2], said arrangement's single main bore may bear 10,920-psi burst and 10,982-psi collapse according to a APT Bulletin 5C3 calculation, wherein a 10,000 psi weB design is the predominant standard for the industry, and wherein boring large diameters, e.g. 36" for the 30" casing and 26"-17" for the 24" casing to hundreds of metres or thousands of feet is common for apparatuses presently being used within the industry.

[0317] Referring now to Figures 113, 114, 115, 116. 117 and 118, illustrating a plan view with line AM-AM, devation cross-section along line AM-AM of Figure 113 with break lines showing sections removed, an isometric projection of the Figure 114 with detail lines AN and AO, a magnified detail view within line AN of Figure 115, a magnified detail view within line AU of Figure 115, and an exploded view associated with the components of Figures 113-117, respectively, of a large diameter high pressure conduit system (1) embodiment (lAG), shown as a dashed line, with a chamber junction (21) side-pocket whipstock conduit (48) assembly embodiment (48B) with concentric and axially autonomous snap-together connector (49) embodiments (491-1, 491), illustrating how a chamber junction (21) maybe used as a side pocket whipstock (33) embodiment (33C).

[03181 The conduit body (4) assembly has an 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 chamber junction conduit, wherein the bore (199) is usable for drilling a strata passage and placing a protective metal lining within the strata passageway and axially autonomous (34) bore (199) extending axially downward and laterally outward from a lower end whipstock (e.g. 46 of Figure 121) to exit the outside diameter the conduit assembly (48) at an axial inclination, wherein the axis of said 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).

[0319] Supporting conduits (246) also foirn part of the conduit assembly (48B), wherein it is usable to, for example, improve fluid circulation andfor cementing operations, provide a gas lift conduit or 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), where an upper snap connector embodiment has three PBR receptacles for conesponding to the chamber junction. supporting conduits and associated mandrel seal stacks of a colTesponding axially autonomous conduit assembly. The lower end four seal stack mandrels (249, 250) and adapted chamber junction (248, 21J) engagable to the conduit housing (247) with a bracket (2001) are engagable to an associated lower axially autonomous conduit whipstock assembly (e.g. 48C of Figures 120-125).

[0320] Figures 119, 1 19A, I 19B, I 19C. I 19D and I 19E 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 p'ug (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, illustrating various diverting apparatuses usable with the present invention.

[03211 The kick-over tool (33K) embodiment (33Kl of Figure 119) may be used for setting 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 andlor axially rotatable from a pivot point (196), for examp'e if a second kick-over arm (195 of Figure 130-131) is attached to the first pivot arm. A kick ovcr tool's running position may comprise, for example, engagement to a running tool that is released after setting a 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 tool, for examp'e drill strings) off of the movable arm (195) andlor engagement/disengagement spnng (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 with the present invention, for example any casing packer which may be set and retrieved and be used as a deflecting apparatus without significant damage to the tool or the well.

[0322] As described any tool acting as an aim 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 (2 Ii) contr&s the orientations of equipment entering the area of the side pocket whipstock. For example, the deflection tool (25B of Figure 1 19B) 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 place in the chamber junction.

[0323] The diverting apparatuses (25) shown as a plug (25A of Figure 1 19A) and manifold crossover turbine (25C of Figure 1 19C) 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-tool if, for example, 25B whipstock (146) arrangement acting as a pivot arm when placed upon the upper end arm (195 of Figure I 19A) of the p'ug (25A).

[0324] The manifold crossover turbine (25C) with upper end running mandrel (257) is usable to drive andlor assist one flow stream with the flowing energy of another, wherein when placed within a receptacle profile a manifold crossover (e.g. 20W of Figure 62, 2OAA of Figure 65 and 20Y of Figures 66-68, at the point of crossover between annulus and inner bore, one flow stream drives a one turbine (258) which through a conmion axial drives the opposite turbine (259) to energize the fluid flow associated with that turbine, or vice versa. Such a turbine may be used with, for example, production moving through a subterranean separator (11) where the expansion of a gas entrained fluid past the turbine into the tank (13) is used to lift dense fluid production or drive water injection andlor disposal.

[0325] The straddle 25E of Figure 11 9E, 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 e.g. crossover ports, wherein operation of the port may simple comprise installing and removing such sealaNe straddles which allow fluid andlor tool passage through an interior passageway and may easily be snapped into and removed from downhole nipple profiles.

[0326] Referring now to Figures 120 and 121, 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 large diameter high pressure conduit system (1) embodiment (JAM), shown as a dashed line, with a side-pocket (48) whip-stock (46) embodiment (48C) with axially autonomous snap-together connector (49) embodiments (491, 49J), showing 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 aterally outward from a thwer end whipstock (46) to exit the outside diameter the conduit body (48), wherein a kick-over tool may be placed in the through passage (198) to access the lateral bore (199).

The upper end connector (491) of the conduit assembly (48C) may be used to engaged kick-over tools, e.g. (33K 1) of Figure 119 or a chamber junction arrangement (e.g. 48B o Figures 113-118) may be added to its lower end.

[0327] Figures 122, 123, 124 and 125, a plan view with AQ-AQ, a 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, of a large diameter high pressure conduit system (1) embodiment (1AI), shown as a dashed line, with 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 (491-1, 491, 49J), showing a diverting (25) kick-over tool (33K) embodiment (33K1) installed in a through passageway (198) in a first running position (33K1A) of unengaged packer slips (197) and a second position (33K1B) for equipment diversion through the side pocket bore (199) use the arm (195) also used for running and retrieving the apparatus.

[0328] Referring now to Figures 126 and 127, a plan view with line AT-AT and an elevation cross section view along line AT-AT with break lines representing removed portions, of a large diameter high pressure conduit system (1) embodiment (IAJ). shown as a dashed line, with a side-pocket conduit (48) whip-stock (46) embodiment (48E), illustrating side pocket (33) embodiment (33E) with a conduit body (48) with upper and lower ends engagable to any form of subterranean connector, wherein the through bore (198) is the inside diameter of the conduit (48) and an axially autonomous (34) bore (199) side pocket is formed on its inside diameter between upper and lower end, and wherein the lateral bore (199) may be usable for urging a strata passage and hanging a protective metal lining across the resulting strata passageway and lateral bore extending axially downward and laterally outward from a lower end whipstock (46) to exit the outside diameter of the containing conduit (48). A kick-over tool is usable to access said autonomous bore (199) from said through passageway (198) as shown in Figures 128-132. Additional supporting axially autonomous conduits may be placed secured with a bracket (263).

[03291 Figures 128 and 129, a plan view with line AU-AU and an elevation cross section view along line AU-AU with break lines representing removed portions, of a large diameter high pressure conduit system (I) embodiment OAK). shown as a dashed line, with a side-pocket conduit (48) whip-stock (46) embodiment (48F), side pocket (33) embodiment (33F) and kick-over tool (33K) embodiment (33K2), illustrating the kick-over tool in the running position (33K2A).

[0330] 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 compnse an elongate body (197) with an arm (195) movable with said body and, axially rotatable from a pivot point (196) using, for example, a j-slot (260) arrangement with said elongate body, between a first, running and retrieving position (33K2A), and a second position (33K2B of Figures 130-132) for the said arm to place or retrieve equipment to and from the lateral bore (199) of said side pocket (33) whipstock conduit (48).

The tool (331(2) is 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 and any other suitable downhole apparatus, to and from said lateral bore with said movable arm.

[0331] Referring now to Figures 130, 131, 132, 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, of a large diameter high pressure conduit system (1) embodiment (1AL), shown as a dashed line, with a side-pocket (33) whip-stock (46) conduit (48) embodiment (48G) with a kick-over tool (33K) embodiment (331(2) shown in the diverting position (33K2B). Any type of piston packer (261) and rod (262) aMlor 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 the running and retrieving position (33K2A), for example the tool (33K2) may be engaged to the through bore (198) with a kidney shaped profile orientating the arm and providing indication of 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, for example, a piston (261) and rod (262) moved axially upward to operate the j-sot (260) and pivot point (196) of the diverting arm (195). Accordingly 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, such as adaptation of a kick-over tool used for gas lift valves modified for the larger bores of the present invention may be used.

[0332] The pass through bore (198) of conduit (48) and its overall axial length before encountering or between side pockets (33) may be significant, e.g. measured in hundreds of feet or metres. to allow a drill string comprising, e.g.. a pendu'um assembly, rotary steerable, bent housing and motor, or other boring assembly using, e.g., drill collars, stabilizers, bits, bi-centre bits, hole openers, or other boring devices, to rotate at modest inclinations, e.g. 1-3 degrees per 30 metres or 100 feet.

when exiting the side pocket (33) which may also have an axia' length measured in the hundreds of feet or metres to allow the installadon of, e.g. a liner hanger.

[03331 As demonstrated, the use of a side-pocket (33) whipstock conduit (48) and kick-over tool of the present invention is generally not applicable to conventional well design, unless sufficient space and pressure bearing capacity is available, hence a LDI-IP 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 is conventionally possible, using conventional apparatuses designed for single bore liners and not necessarily conventional tools designed for multilateral s. According] y, any multilateral tool current] y available may be adapted to work with the present invention, in the same manner as conventional well designs, with the significant benefit of using larger hole sizes.

[0334] The construction of wells, generally, began with dropping heavy cable tools to cut a circular hole of up to 14 inches by the Chinese around 600 to 260 BC and cable tool drilling began in Europe around 1825 AD until a two cone drill bit was patented in 1879 AD and a tn-cone bit introduced in 1933, after which rotaly drilling dominated well construction and an industry that was first plagued by boom and bust, and then over supply, wherein supply was controlled as descnbed by Yergin and low cost standardization became the rule. During the ater parts of the last century significant advances in supplying torque and weight to subtelTanean boring bits and construction of large diameter steel casings occurred, however the industry has continued to search for hydrocarbons that fit the bore hole sizes designed for easily accessible "conventional" subterranean deposits which dominated its history during periods when insufficient power was available to drill larger bore holes economically.

[0335] Accordingly, the present invention is neither obvious to practioners who have used substantially the same well bore size at least 200 BC, nor is it necessarily the lowest cost option for in various areas where surface strata is particularly difficuli to bore even with our current level of technology; however, a very serious need exists to access unconventional and extremely difficult subterranean deposits, as taught by Yergin, and wherein providing subterranean processing in remote and subsea locations reduce the required infrastructure and to reduce the number of penetrations through ground water systems and/or moderate the use of surface areas in environmentally sensitive areas, forests, farmlands andior populated areas where drilling and well production have significant negative impact. The large bore high pressure conduit system (1) described herein. may be used to meet such needs in a cost and carbon footprint conscious manner, by reducing surface impact to vegetation, niinimising fuels and resources used to construct a plurality of wells and providing a design for more economically producing and maxirnising recover of cleaner burning fuels, such as gas, wherein present modern advances in subtenanean technothgies may be used to control producible and/or injectable subterranean single or simultaneous fluid flow streams of varying velocities to andlor from one or more wells through a single main bore with pressure bearing capacities greater than are presenfly practiced using larger diameter conduits to access conventional and unconventional subterranean deposits with a design that usable with virtually any off-the-shelf field proven techn&ogy and may be standardized to further reduce costs and environmental impact.

[03361 While various embodiments of the present invention have been described with emphasis, it should be understood that within the scope of the appended claims, the present invention might be practiced other than as specifically described herein.

[0337] Reference numerah have been incorporated in the claims purely to assist understanding during prosecution.

Claims

CLAIMSThe embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows: A well conduit system (1) with large diameter higher pressure conduit containment, comprising: concentrically placed first (2) and at least second (3) conduits with continuous elastically compressible outer and expandable inner pipe body (4) circumferences from which a plurality of radiafloading surfaces (5,6,41, 42, 49, 123) extend across at least a portion of and radially from at least one of said circumferences of at least one of said first and at least second conduits through the at least one concentric annular space (7) between said conduits to engage said plurality of radial loading surfaces to an associated loading surface and circumference, thus abutting one of said conduits to another, wherein the effective diameter of said radia' thading surface is greater than the effective diameter of said associated loading surface and circumference prior to adjoining said radial loading surface into said colTesponding loading surface and circumference to elastically expand and compress said diameters to consequendy abut said loading surface to said corresponding circumference to share hoop stress resistances (8) between said first and at least second conduits with said abutment to foim a greater effective wall thickness (9) capable of bearing higher pressures than said conduits could independently bear, to, in use, control fluid communication between injectable and producible strata of one or more well passageways extending from at least one wellhead assembly (10) secured to the upper end of said first and at least second conduits to said strata, through exits at the lower end of said first and at least second conduits.
2. The well conduit system according to claim I, with said radial loading surfaces comprising part of at least one of said compressible outer and expandable inner pipe body circumferences 4), independent bearings intermediate to said compressible outer and expandable inner pipe body circumferences, or combinations thereof.
3. The well conduit system according to claim 1 or claim 2. with said radial loading surfaces comprising a partially plastic deformable portion and elastically expandable portion providing said abutment to share said hoop stress resistances (8) between said first and at least second conduits.
4. The well conduit system according to any preceding claim, with said adjoining of said first (2) and at least second (3) conduits comprising the use of gravity, mechanical (38), pneumatic (39), hammering, or combinations thereof, forces to cause said expansion and compression of said effective load surface diameters.
5. The well conduit system according to any preceding claim, further comprising a wellhead assembly (10) of at least one fluid communication conduit hanger spool (14) subassembly. engaged with securable (15) and sealable (16) components to first (17) and at least second (18) conduit head subassemblies associated with and secured to the upper end of said first (2) and said at least second (3) conduits, with said at least one spool subassembly engaged at the upper end of said first and at least second or between said first and at least second conduit head subassemblies to form said wellhead assembly.
6. The well passageways according to any preceding claim, comprising a plurality of substantially concentric (35), axially autonomous conduits (34), or combinations thereof (47), extending axially downward between said at least one wellhead assembly and the lower end of said one or more wells.
7. The well passageways according to claim 6, comprising a plurality of concunently engagable and axially parallel associated axially autonomous conduit (34) snap connectors (49) with elastically compressible outer and expandable inner circumferences (4A) associated with said pipe body (4) circumferences to, in use, connect a plurality composite joints of substantially concentric (35). axially autonomous (34), or combinations thereof.
8. The well conduit system according to any preceding claim, with said well passageways comprising autonomous or connecting inner, annular, lateral (194). or combinations thereof, passageways controlling said fluid communication.
9. The connecting well passageways according to claim 8, further comprising one or more manifold crossovers (20), chamber junctions (21), side-pocket whipstock (48), or combinations thereof, engaged between said at least one welihead assembly (10) and said injectable and producible strata of said one or more wells to selectively control communication of apparatuses and said fluid communication with arrangements of valves (24) and diverting apparatuses (25) selectively placed within said one or more passageways or through said wefihead and inner passageway using a bore selector (32) or kick-over tool (33K).
10. The well conduit system according to claim 9, with said 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 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 said conduit at an axial inclination, wherein the axis of said autonomous bore is axially and laterally offset from the through passage (198) of said conduit such that the upper end of said autonomous bore is below the upper end of said conduit and engagable with a kick-over tool to access said autonomous bore from said through passageway.
11. The well conduit system according to claim 9 or claim 10, with said selective placement comprising at least one bore selector tool (32), kick-over tool (33K), or combinations thereof, selectively placed through said inner passageway and oriented to an orifice of said chamber junction to access an exit bore thereof for placement of said valves (24) or diverting apparatuses (125) within said manifold junction or chamber junction to provide said selective apparatus and fluid communication with said one or more wells.
12. The well conduit system according to claim 11, with said kick-over tool (33K) comprising a tool for placing or retrieving well equipment via a through passage (198) of a conduit adjacent to said side pocket whipstock lateral bore (199). said kick-over to& comprising an elongate body (197) with an arm (195) movable with said body.axially rotatable from a pivot point (196) on said elongate body, or combinations thereof, between a first, running and retrieving position, and a second position for using 1T1 said arm to place or retrieve equipment to and from the lateral bore of said side pocket whipstock by placing and retrieving said kick-over tool in the first position and using the second position to engage the upper end of said elongate body proximally to said lateral bore so as to divert said equipment to and from said lateral bore with said movable arm.
13. The well conduit system according to any preceding claim, comprising at least one boring assembly axial lower end (45). axial and ateral whip-stock (46, 48), or combinations thereof, onfice exist from said substantially concentric (35) or axially autonomous conduits (34) for boring strata and placing conduits within said strata and well conduit system.
14. The well conduit system according to any preceding daim, further comprising fluid communication with a subterranean fluid processing tank (13) formed within and between said wellhead and the lower end of said first and at least second conduit so as to surround and fluidly communicate with at least one of said one or more well passageways.
15. The fluid communication according to claim 14, further comprising using said tanlc (13) to form a subterranean separator (11) with connecting substantially concentric or axially autonomous conduit walls and passageways forming inlets (26), chimneys (27), downcomers (28), diverters (29), spreaders (30), mist extractors (31), or combinations thereof, to separate water, liquid and gas hydrocarbons to perform said fluid processing.
16. The fluid communication according to claim 14, further comprising using said tank (i3) to form a heat exchanger (12) with substantially concentric or axially autonomous conduit walls exchanging heat between fluid within said conduits and fluid within said tank to perform said fluid processing.
17. The well conduit system according to any preceding claim, with fluid communication comprising the division or commingling of fluid flow streams through said autonomous or connecting one or more well passageways within said first and at least second conduits at various depths to process or separate said fluids for injection or production.
18. The well conduit system according to claim 17, comprising selective control of simultaneous flow streams with one or more of said vahes (24) or diverting apparatuses (25) placed within said autonomous or connecting one or more passageways.
19. The well conduit system according to any preceding claim, comprising conduits and associated apparatuses engaged by friction, welding, mandrels, dogs, receptacles, slots, slips, threads, bolts, clamps, hoop stress resistances, or combinations thereof, connectors.
20. The well conduit system according to any preceding claim, comprising metal-to-metal.elastomeric, cement, or combinations thereof, sealing of said fluid communication passageways and said engagement of conduits and associated apparatuses.
21. The well conduit system according to any preceding claim, compnsing the use of single (41) or double olive (42) compression fittings to secure and seal two components of said welihead assemNy together or to seal and secure said at least second conduit (3) within: said first conduit (2), a surrounding another at least second conduit, said spool (14) subassembly, said wellhead (10) assembly, or combinations thereof 22. The well conduit system according to any preceding claim, comprising directionally boring and placing protective linings in said one or more wells to provide said fluid communication between said injectable and produciNe strata and said at east one wellhead assembly (10).23. The well conduit system according to any preceding claim, comprising external compression fluid (43) communication between said welihead assembly and said injectable and producible strata, between said wellhead assembly and conduits exporting fluids from said one or more wells, or combinations thereof.24. The fluid communication according to any preceding claim, selectively controlled by computer operation (102, 108) of said valves using electrical, pneumatic, hydraulic, or combinations thereof, motors and connections also usable for observation of pressures, temperatures and flow-rates associated with said one or more passageways.25. A method for using a well conduit system (I) with large diameter higher pressure conduit containment, comprising: placing concentricafly first (2) and at east second (3) conduits with continuous elastically compressible outer and expandable inner pipe body (4) circumferences from which a plurality of radial loading surfaces (5, 6, 41, 42, 49, 123) extend across at least a portion of and radially from at least one of said circumferences of at least one of said first and at least second conduits through the at least one concentric annular space (7) between said conduits to engage said plurality of radial loading surfaces to an associated loading surface and circumference, thus abutting one of said conduits to another, wherein the effective diameter of said radial loading surface is greater than the effective diameter of said associated loading surface and circumference prior to adjoining said radial loading surface into said conesponding loading surface and circumference to elastically expand and compress said diameters to consequently abut said loading surface to said corresponding circumference to share hoop stress resistances (8) between said first and at least second conduits with said abutment to form a greater effective wall thickness (9) capable of bearing higher pressures than said conduits could independently bear, to, in use, control fluid communication between injectable and producible strata of one or more well passageways extending from at least one wellhead assembly (10) secured to the upper end of said first and at least second conduits to said strata through exits at the lower end of said first and at least second conduits.26. The method according to claim 25, with the step of providing radial loading surfaces comprising part of at least one of said compressible outer and expandable inner pipe body circumferences (4), independent bearings intermediate to said compressible outer and expandable inner pipe body circumferences, or combinations thereof.27. The method according to claim 25 or claim 26, with the step of providing radial loading surfaces comprising a partially plastic deformable portion and elastically expandable portion providing said abuilnent to share said hoop stress resistances (8) between said first and at least second conduits.28. The method according to any claims 25 to 27, with the step of adjoining said at least second (3) conduit within said first (2) conduit using gravity, mechanical (38), pneumatic (39), hydrauhc (40), or combinations thereof, forces to cause said expansion and compression of said effective load suiface diameters.29. The method according to any claims 25 to 28, with the step of providing a wellhead assembly (10) of at least one fluid communication conduit hanger spool (14) subassembly, engaged with securable (15) and sealable (16) components to first (17) and at least second (18) conduit head subassemblies associated with and secured to the upper end of said first (2) and said at least second (3) conduits, with said at least one spool subassembly engaged at the upper end of said first and at least second or between said first and at least second conduit head subassemblies to form said wellhead assembly.30. The method according to any claims 25 to 2c,w ith the step of providing a plurality of substantially concentnc (35), axially autonomous (34), or combinations thereof (47), conduits extending axially downward between said at least one wellhead assembly and the lower end of said one or more wells.31. The method according to any claim 30, with the step of providing a plurality of concurrently engagable and axially parallel associated axially autonomous conduit (34) snap connectors (49) with elastically compressible outer and expandable inner circumferences (4A) associated with said pipe body (4) circumferences to, in use, connect a plurality composite joints of substantially concentric (35). axially autonomous (34), or combinations thereof,.32. The method according to claim 25 to 3i, with the step of providing autonomous or connecting inner, annular, lateral (194), or combinations thereof, passageways controlling said fluid communication.33. The method according to any claims 25 to 32, with the step of providing one or more manifold crossovers (20), chamber junctions (21), side-pocket whipstock (48), or combinations thereof, engaged between said at least one wefihead assembly (10) and said injectable and producible strata of said one or more wells to selectively control communication of apparatuses and said fluid communication with arrangements of valves 24) and diverting apparatuses (25) selectively placed within said one or more passageways or through said wefihead and inner passageway using a bore selector (32) or kick-over tool (33K).34. The method according to any claim 33, with the step of providing a side pocket (33) comprising a conduit body with upper and lower ends and an axially autonomous bore side pocket formed between said ends on the inside diameter of said conduit, with said bore being usable for urging a strata passage and hanging a protective metal lining across said strata passageway and said autonomous bore extending axially downward and laterally outward from a lower end whipstock to exit the outside diameter of said conduit at an axial inclination, wherein the axis of said autonomous bore is axially and laterally offset from the through passage of said conduit such that the upper end of said autonomous bore is below the upper end of said conduit and engagable with a kick-over tool to access said autonomous bore from said through passageway.35. The method according to claim 33 or claim 34, with the step of providing at least one bore selector tool (32), kick-over tool (33K), or combinations thereof, selectively placed through said inner passageway and oriented to an orifice of said chamber junction to access an exit bore thereof, for placement of said valves (24) or diverting apparatuses (25) within said manifold junction or chamber junction to provide said selective apparatus and fluid communication with said one or more wells.36. The method according to claim 35, with the step of providing kick-over tool compi-ising a to& for placing or retrieving well equipment via a through passage of a conduit adjacent to said side pocket whipstock latera' bore, said kick-over tool comprising an elongate body with an arm movable with said body, axially rotatable from a pivot point on said elongate body, or combinations thereof, between 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 said side pocket whipstock by placing and retrieving said kick-over tool in the first position and using the second position to engage the upper end of said elongate body proximally to said lateral bore so as to divert said equipment to and from said lateral bore with said movable arm.37. The method according to any claims 25 to 36, with the step of providing at least one boring assembly axial lower end (45). axial and latera' whip-stock (46, 48), or combinations thereof, orifice exist from said substantially concentric (35) or axia'ly autonomous conduits (34) for boring strata and placing conduits within said strata and well conduit system.38. The method according to any claims 25 to 37, with the step of providing a subterranean fluid processing tank (i3) formed within and between said welihead and the lower end of said first and at least second conduit so as to surround and fluidly communicate with at least one of said one or more well passageways.39. The method according to claim 38. with the step of forming a subtelTanean separator with connecting substantially concentric or axially autonomous conduit walls and passageways forming inlets (26), chimneys (27). downcomers (28). diverters (29), spreaders (30), mist extractors (31), or combinations thereof, to separate water, liquid and gas hydrocarbons to perform said fluid processing within said tank.40. The method according to claim 38, with the step of forming a heat exchanger (12) with substantially concentric or axially autonomous conduit walls exchanging heat between fluid within said conduits and fluid within said tank to perform said fluid processing.41. The method according to any claims 25 to 40, with the step of providing fluid communication comprising the division or commingling of fluid flow streams through said autonomous or connecting one or more well passageways within said first and at least second conduits at vanous depths to process or separate said fluids for injection or production.42. The method according to any claims 25 to 41, with the step of selectively controlling simultaneous flow streams with one or more of said va'ves (24) or diverting apparatuses (25) placed within said autonomous or connecting one or more passageways.43. The method according to any claims 25 to 42, with the step of providing fnction, welded, mandrel, dogged, receptacle, slotted, slips, threads, bolted, clamped, hoop stress resistance, or combinations thereof, connector engagements between conduits and associated apparatus of said well conduit system.44. The method according to any claims 25 to 43, with the step of providing metal-to-metal. elastomeric. cement, or combinations thereof, sealing of said fluid communication passageways and said engagement of conduits and associated apparatuses.45. The method according to any claims 25 to 44, with the step of using single (41) or double (42) olive compression fittings to secure and seal two components of said wefihead assembly together or to seal and secure said at least second conduit (3) within: said first conduit (2), a sulTounding another at least second conduit, said spooi (14) subassembly, said wellhead (10) assembly, or combinations thereof.46. The method according to any claims 25 to 45, with the step of directionally boring and placing protective linings in said one or more wells to provide said fluid conmiunication between said injectable and producible strata and said at least one wellhead assembly.47. The method according to any claims 25 to 46, with the step of providing said one or more wells in a vertically, laterally, or combinations thereof, spacing and axially orientation.48. The method according to any claims 25 to 47, with the step of providing external compression (43) fluid communication between said wellhead assembly and said injectable and producible strata, between said welihead assembly and conduits exporting fluids from said one or more wells, or combinations thereof.49. The method according to any claims 25 to 48, with the step of selectively controlling fluid communication by computer operation (102. 108) of said valves using electrical.pneumatic, hydraulic, or combinations thereof, motors and connections also usable for observation of pressures, temperatures and flow-rates associated with said one or more passageways.50. The method according to any claims 25 to 49. with the step of hydraulically fracturing said strata from one or more wells individually or simultaneously.51. A well conduit system (I) with large diameter higher pressure conduit containment using conduit hoop stress resistance sharing (8) between at least two conduits (2, 3) to form a greater effective conduit wall thickness (9) capable of bearing the pressures of fluid communication and processing from one or more subtelTanean wells, said system being substantially as described hereinabove with reference to Figures 5 to 15, Figures i7 to 39 and Figures 45 to i32 of the accompanying drawings Figures.52. A method of using a well conduit system (1) with large diameter higher pressure conduit containment hoop stress sharing (8) between at least two conduits (2, 3) to form a greater effective conduit wall thickness (9) to bear the pressures of fluid communication and processing from one or more subterranean wells, the method being substantially as described hereinabove with reference to Figures 5 to IS. Figures 17 to 39 and Figures 45 to 132 of the accompanying drawings Figures.Amendment to the claims have been filed as followsCLAIMSThe embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows: A well conduit system (1), comprising: a first (2) circumferentially dastic outer conduit wall; at least one second (3) circumferentially elastic inner conduit wall positioned within the first circumferentially elastic outer conduit wall to define an annulus between the first circumferentially elastic outer conduit wall and said at least one second circumferentially dastic inner conduit wall; a plurality of radial load surfaces (5, 6. 41, 42, 49. 123) extending across the annulus and radially between at least two of said conduit walls to concentrically abut against at least one other of said conduit walls to form at least two elastic hoop stress adjoined c") pipe bodies (4) with at least one concentric annulus space (7) between said at least two elastic hoop stress adjoined pipe bodies and said plurality of radial load surfaces, 0 wherein one or more passageways through subterranean strata is formed by inserting an inner pipe body comprising said at least one second circumferentially elastic inner conduit wall into an outer pipe body comprising the first circumferentially elastic outer conduit wall, wherein the inner pipe body comprises an outer diameter greater than an inner diameter of the outer pipe body, and wherein the inner pipe body is inserted into the outer pipe body below at least one wellhead assembly (10), using a circumferentially elastic expansion of said outer pipe body and a circumferentially elastic compression of said inner pipe body resulting from a hoop force exerted therebetween, and wherein the release of said hoop force after said insertion releases said circumferentially elastic expansion and said circumferentially elastic compression to abut said plurality of radial load surfaces of said outer pipe body to said inner pipe body for forming adjoined pipe bodies, and to cause a concentric sharing of elastic hoop stress resistance (8) between said adjoined pipe bodies for forming a greater effective wall thickness (9) that is capable of containing higher pressures than said conduit walls could otherwise bear without said concentric sharing of said elastic hoop stress resistance.2. The well conduit system according to claim 1, wherein said radial loading surfaces comprise a portion of at least one of said pipe bodies (4), a portion of an independent bearing intermediate to the at least one of said pipe bodies, or combinations thereof.3. The well conduit system according to claim 1 or claim 2, wherein said radial loading surfaces comprise a plastic deformable portion or an dasticaily expandable portion usable to provide said abutment of said plurality of radial load surfaces and said concentric sharing of said elastic hoop stress resistance (8) between said adjoined pipe bodies.4. The well conduit system according to any preceding claim, wherein said hoop force comprises gravity forces, hammering forces, mechanical forces (38). fluid or pneumatic forces (39), or combinations thereof.r 5. The well conduit system according to any preceding claim, further comprising a cv') wellhead assembly (10) of at least one fluid communication conduit hanger spool (14) O subassembly. engagable with securable (15) and sealable (16) components to a first (17) conduit head subassembly and at least one second (18) conduit head subassembly.0 wherein the first (17) and at least one second (18) conduit head subassemblies are associated with and secured to an upper end of said first (2) circumferentially elastic outer conduit wall and said at least one second (3) circumferentially elastic inner conduit wall to form said wellhead assembly.6. The well conduit system according to any preceding claim, wherein single (41) or double olive (42) compression fittings are used to secure and seal at least two conduit walls engaged to said wellliead assembly.7. The well conduit system according to any preceding claim, further comprising at least one boring assembly (lB. IC. IG, IH) engagable with said wellhead assembly to urge said one or more passageways through the subterranean strata.8. The well conduit system according to any preceding daim. wherein a plurality of substantially concentric conduits (35), axially autonomous conduits (34). or combinations thereof (47). form composite joints that are disposable through said pipe bodies to form said one or more passageways through the subterranean strata.9. The well conduit system according to claim 8, wherein said composite joints comprise a plurality of parallel axially autonomous concurrently engagable conduit (34) snap connectors (49) that comprise elastically compressible inner circumferences and elastically expandable outer circumferences (4A) for connecting substantially concentric conduits (35) or axially autonomous (34) conduits.10. The well conduit system according to claim 8, wherein one or more valves (24) or diverting apparatuses (25, 32, 33K) are selectively disposed to control communication through said one or more passageways through the subterranean strata.11. The well conduit system according to claim 10, wherein said controlled communication comprises using a computer (102, 108) to operate said valves or to operate said diverting apparatuses (25, 32, 33K) by using observed pressures. temperatures and 0') flow-rates of fluids for communicating fluids through said one or more passageways r through the subterranean strata. Co0 12. The well conduit system according to claim 8, further comprising one or more autonomous bores formed with a manifold crossover (20), a chamber junction (21), a 0 side-pocket whipstock (48), or combinations thereof 13. The well conduit system according to daim 12, wherein said side-pocket whipstock (48) comprises a side pocket (33) with an axially autonomous (34) bore (199) extending to a lower end whipstock (46) that is laterally offset from the through passage (1198).14. The well conduit system according to claim 12 or claim 13, wherein at least one bore sdector tod (32), a kick-over tool (33K), or combinations thereof, are selectively disposed through and onented to said one or more passageways to access said autonomous bore.15. The well conduit system according to claim 14, wherein said kick-over tool (33K) comprises an elongate body (197) with a movable arm (195), an axially rotatable pivot point (196), or combinations thereof, usable for placing or retrieving weB equipment through said side-pocket whipstock lateral bore (199) via said through passage (198).1 6. The wefl conduit system according to any preceding claim, wherein a subterranean fluid processing tank (13) is formed within said pipe bodies, between said at least one welihead assembly and the lower end of said pipe bodies, and wherein said fluid processing tank surrounds and fluidly communicates with at least one of said one or more passageways through the subterranean strata.17. The well conduit system according to claim 16, wherein said subterranean fluid processing tank (13) is used to form a subterranean separator (II) comprising connecting substantially concentric or axially autonomous conduit walls and passageways that form inlets (26), chimneys (27), downcorners (28), diverters (29), spreaders (30), mist extractors (3 I), or combinations thereof, to separate fluids during said fluid processing.18. The well conduit system according to claim 16, wherein said subterranean fluid processing tank (13) forms a heat exchanger (12) using said connecting substantially ce') concentric or axially autonomous conduit walls to exchange heat between fluid within r said connecting substantially concentric or axially autonomous conduit walls and fluid ci') about said connectthg substantially concentric or axially autonomous conduit walls C within said subterranean fluid processing tank, to further provide said subterranean fluid processing.C19. A method of using a well conduit system (1). said method comprising the steps of providing a circumferentially elastic outer conduit wall (2) and at least one second circumferentially elastic inner conduit wall (3) or combinations thereof, with a plurality of radial load surfaces (5, 6, 41,42, 49, 123) extending across at least a portion of and radially between at least two of said conduit walls to concentrically abut against at least one other of said conduit walls to form at least two elastic hoop stress adjoined pipe bodies (4) with at east one concentric annulus space (7) between said adjoined pipe bodies and said plurality of radial load surfaces; forming one or more passageways through subterranean strata by inserting an inner pipe body comprising said at least one second circumferentially elastic inner conduit wall into an outer pipe body comprising the circumferentially elastic outer conduit wall, wherein the inner pipe body comprises an outer diameter greater than an inner diameter of the outer pipe body, and wherein the inner pipe body is inserted into the outer pipe body below at least one wefihead assembly (10) using circumferentially elastic expansion of said outer pipe body and a circumferentially elastic compression of said inner pipe body resulting from a hoop force exerted therebetween; and releasing said hoop force after said insertion to release said circumferentially elastic expansion and said circumferentially elastic compression and abut said plurality of radial load surfaces of said outer pipe body to said inner pipe body for forming adjoined pipe bodies and to cause a concentric sharing of elastic hoop stress resistance (8) between said adjoined pipe bodies for forming a greater effective wall thickness (9) that is capable of containing higher pressures than said conduit walls could otherwise bear without said concentric sharing of said elastic hoop stress resistance 20. The method according to daim 19, further comprising using at least a part of at least one of said pipe bodies 4) as said plurality of radial load surfaces, using independent bearings intermediate to said pipe bodies as said plurality of radial load surfaces, or combinations thereof. r.21. The method according to claim 19 or claim 20, further compnsmg using plastic c") deformable radial load surfaces or dastically expandable radial toad surfaces to provide said abutment and to share said elastic hoop stress resistances (8) between said adjoined pipe bodies.
22. The method according to any of claims 19 to 21, further comprising using gravity hoop forces, hammering hoop forces, mechanical hoop forces (38), fluid or pneumatic hoop forces (39), or combinations thereof.
23. The method according to any of claims 19 to 22, further comprising the step of forming a welihead assembly (10) 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 an upper end of said circumferentially elastic outer conduit wall (2) and said at least one second circumferentially elastic inner conduit wall (3).
24. The method according to any of claims 19 to 23, further comprising using single (41) or double olive (42) compression fittings to secure and seal at east two walls engaged to said wellhead assembly.
25. The method according to any of chirns 19 to 24, further comprising using at least one boring assembly (1B, 1C, 1G, 1H) engagable with said wellhead assembly to urge said one or more passageways through the subtemmean strata.
26. The method according to any of claims 19 to 25, further comprising providing composite joints formed with a plurality of substantially concentric conduits (35), axially autonomous conduits (34), or combinations thereof (47), disposable through said pipe bodies to further form said one or more passageways through the subterranean strata.
27. The method according to claim 26, further comprising using a plurality of parallel axially autonomous concurrently engagable conduit (34) snap connectors (49) with elastically compressiNe inner circumferences and dastically expandable outer circumferences (4A) to connect said substantially concentric conduits (35) or axially autonomous (34) conduits.C")
28. The method according to claim 26, further comprising selectively disposing one or r more valves (24) or diverting apparatuses (25, 32, 33K) in said one or more passageways to control communication through said one or more passageways.
29. The method according to claim 28, further comprising using a computer (i02, 108) to 0 control fluid communication by operating said valves or said diverting apparatuses using observed pressures, temperatures or flow-rates of fluids communicated through said one or more passageways through the subterranean strata.
30. The method according to claim 26, further comprising the step of forming one or more autonomous bores with a manifold crossover (20), chamber junction (21), side-pocket whipstock (48), or combinations thereof.
31. The method according to claim 26, further comprising the step of forming a side-pocket whipstock (48) using a side pocket (33) with an axially autonomous 34) bore (199) extending to a lower end whipstock (46) that is laterally offset from an associated through passage(198).
32. The method according to claim 30 or claim 31, further comprising selectively disposing and orienting at least one bore selector to6l (32), kick-over tool (33K), or combinations within said one or more passageway to access said autonomous bore.
33. The method according to claim 32, further comprising providing said kick-over tool (33K) with an elongate body (197) and a movable arm (195), an axially rotatable pivot point (196), or combinations thereof, usable for placing or retrieving well equipment through said side-pocket whipstock lateral bore (199) via said through passage (198).
34. The method according to any of claims 19 to 33, further comprising the step of communicating fluids using a subterranean fluid processing tank (13) formed within said pipe bodies, between said at least one wellhead assembly and the lower end of said pipe bodies, wherein said fluid processing tank surrounds and fluidly communicates with at least one of said one or more passageways through the subterranean strata.
35. The method according to claim 34, further comprising using said subterranean fluid processing tank (13) to form a subterranean separator (II) with connecting substantially concentric or axially autonomous conduit walls and passageways for forming inlets 0') (26), chimneys (27), downcomers 28), diverters (29), spreaders (30), mist extractors r.. -. . (31), or combinations thereof, to separate fluids dunng said fluid processing. 0)O
36. The method according to claim 34, further comprising using said subterranean fluid processing tank (13) to form a heat exchanger (12) using said substantially concentric 0 or axiafly autonomous conduit wafis to exchange heat between fluid within said walls and fluid about said walls within said subterranean fluid processing tank, to further provide said subterranean fluid processing.
37. A well conduit system (1) with large diameter higher pressure conduit containment using conduit hoop stress resistance sharing (8) between at least two conduits (2, 3) to foirn a greater effective conduit wall thickness (9) that is capable of bearing the pressures of fluid communication and processing from one or more subterranean wells, said system being substantially as described hereinabove with reference to Figures 1 to 14, Figure 15, Figures 17. 17A and 17B, Figures 18 to 39 and Figures 45 to 132 of the accompanying drawings Figures.
38. A method of using a well conduit system (1) with large diameter higher pressure conduit containment hoop stress sharing (8) between at least two conduits (2. 3) for fomñng a greater effective conduit wall thickness (9) to bear the pressures of fluid communication and processing from one or more subterranean wells, the method being substantially as described hereinabove with reference to Figures 1 to 14, Figure 15, Figures 17, 17A and 17B, Figures 18 to 39 and Figures 45 to 132 of the accompanying drawings Figures. r