WO1991017339A1 - Method and apparatus for drilling and coring - Google Patents

Method and apparatus for drilling and coring Download PDF

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Publication number
WO1991017339A1
WO1991017339A1 PCT/US1991/002874 US9102874W WO9117339A1 WO 1991017339 A1 WO1991017339 A1 WO 1991017339A1 US 9102874 W US9102874 W US 9102874W WO 9117339 A1 WO9117339 A1 WO 9117339A1
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WO
WIPO (PCT)
Prior art keywords
fluid
borehole
high pressure
drilling
annulus
Prior art date
Application number
PCT/US1991/002874
Other languages
French (fr)
Inventor
Harry Bailey Curlett
Original Assignee
Harry Bailey Curlett
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority to US51612590A priority Critical
Priority to US516,125 priority
Application filed by Harry Bailey Curlett filed Critical Harry Bailey Curlett
Publication of WO1991017339A1 publication Critical patent/WO1991017339A1/en

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Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/02Swivel joints in hose-lines
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00Drill bits
    • E21B10/02Core bits
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00Drill bits
    • E21B10/60Drill bits characterised by conduits or nozzles for drilling fluids
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/12Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor using drilling pipes with plural fluid passages, e.g. closed circulation systems
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00Special methods or apparatus for drilling
    • E21B7/18Drilling by liquid or gas jets, with or without entrained pellets

Abstract

A drilling system that combines advantages of high pressure fluid jet cutting techniques with reverse circulation of borehole fluids through a concentric drill string. The preferred embodiment includes conventional drilling mud flowing in the borehole annulus (60) and a high pressure clarified fluid for discharge through the fluid jet. The concentric drill string (2) and fluid jet drilling tool (1) are used with reverse circulation fluid management to core and/or selectively enlarge a subsurface well bore. The dual-concentric drill string circulates the clarified drilling fluid at high pressures, downwardly, through the annulus (64) formed by the inner (7) and outer (2) pipe strings, through the drilling tool and upwardly through the inner string to continuously circulate drilled cuttings and/or drilled cores out of the well bore. The high pressure fluid is employed with the mechanical action of the drilling tool as a high pressure jet formation cutting system.

Description

Description METHOD AND APPARATUS FOR DRILLING AND CORING BACKGROUND OF THE INVENTION Field of the Invention
The present invention relates to well drilling operations and, more particularly, to a method and apparatus for core drilling and/or boring relatively small diameter subterranean information holes through the use of high pressure jet cutting and reverse circulation fluid management techniques. History of the Prior Art The present invention relates to a method and apparatus for rapidly coring a relatively small diameter well bore and/or enlarging the well bore in a process which is best suited for the exploration of subsurface oil, gas, water and mineral resources. The disclosed method and apparatus provides the technical and operational basis for deriving the economic benefits of the relatively cost effective small diameter resource exploration drilling with the selective use of well bore enlargement drilling only when access to the subsurface production warrants such well bore enlargement.
The technique of slim hole drilling and coring as an exploration tool has long been desired, in particular, by the oil and gas industry, as a means to reduce the expensive geological exploration process of drilling expensive conventional large diameter deep well bores in order to confirm the geological and commercial presence of a subsurface resource. The technique is discussed in "Drilling Operations Manual", 1965, P. Moore, et al. , pp. 12-1-12-7 and "An Innovative Approach to Exploration and Exploitation Drilling: The Slim-Hole High Speed Drilling System," 1989, S. H. Walker et al. , Society of Petroleum Engineer, Paper No. 19525.
Slim hole drilling has been technically feasible, but has not been operationally embraced by the industry due to certain limitations in the manner in which it has been implemented. For example, poor overall penetration rates and adverse well control considerations have plagued slim hole drilling as an exploration technique. With the small annular clearances inherent in slim hole drilling, fluid volume and pressure related problems can become very serious during pressure control emergencies. Moreover, as the hole diameter is reduced, the resultant smaller drill bit bearing surfaces and the operational difficulties inherent in evenly controlling the weights applied to such drill bits, place constraints upon the use of mechanical drill bits. These factors result in premature bit failure and poor overall economics when mechanical bits are used in slim hole drilling operations.
During the 1970' s and early 1980' s, drilling systems employing the use of high pressure fluid jet cutting techniques in combination with mechanical drill bits were proposed and received significant interest and attention from the drilling industry. During this period the oil and gas industry invested substantial money, time and effort in attempting to improve drill penetration rates by employing high pressure fluid jet cutting techniques. These efforts are discussed in "Advanced Drilling Techniques", 1988, W. C. Maurer, Ch. 14.
As field work in high pressure fluid jet drilling progressed, it became apparent that a single fluid drilling system, using conventional "mud", pumped at elevated pressures, as the drilling fluid, was not practical. This was due to the inherent abrasive particle nature of conventional drilling mud which caused, at elevated pressures, excessive erosion of drill bits and the fluid delivery system. These conclusions are discussed in the Department of Energy Report "Research and Development of a High Pressure Waterj et Coring Device for Geothermal Exploration and Drilling - Final Report", 1978, J. Reichman et al.
In an effort to overcome the deficiencies inherent in the use of conventional abrasive fluids for high pressure jet drilling, it was proposed to use two different fluids at the same time: a non-abrasive high pressure fluid for jet drilling and the conventional abrasive drilling fluid at low pressures for other functions necessary in the drilling operation. For example, in U. S. Patent Nos. 4, 691, 790 and 4, 624, 327 to Reichman and U. S. Patent Nos. 4, 836, 305 and 4, 683, 944 to Curlett it is taught that the use of a minimally abrasive, high pressure fluid, in conjunction with a low pressure conventional drilling mud as parts of a multiple component drilling fluid system provides increased borehole penetration rates. Both laboratory testing and actual field operations have demonstrated the viability of such high pressure jet drilling systems in conventional, direct circulation configurations. See, for example, "High Pressure Drilling System Triples ROPS, Stymies Bit Wear", Drilling, March/April 1989 and "Laboratory Testing of High Pressure, High Speed PDC Bits", 1986, W. C. Maurer et al, Society of Petroleum Engineers Paper No. 15615. Multiple conduit drill pipes have even been designed in order to implement a multiple fluid high pressure jet drilling system. The ' 305 Curlett patents disclose a nested multiple tubular drill pipe configuration with partial reverse circulation. The Reichman patents teach a more industry standardized approach of a dual-concentric drill pipe string. Moreover, the use of dual-concentric drill pipe strings is well known in the art as is illustrated, for example, in U. S. Patent Nos. 3,208,539 and 3,552,779, each issued to Henderson; 1, 585, 969 to Ferguson; 2, 786, 652 to Wells; 3,268,017 to Yarbrough; 3,596,720 to Elenburg; 4,319, 784 to Claringbull; and 4,691,790 to Reichman et al.
With the advent of dual-concentric pipe strings, reverse circulation drilling and coring techniques became more widely practiced and was originally used to retrieve competent geological information in the form of cores and/or larger drilled samples in a stratigraphically correct order. The accepted uses in the oil and gas industry are discussed in "New Drilling Technique Recovers 100 Percent Continuous Core", World Oil, January 1960, H. Henderson et al. The use of dual conduit reverse circulation drilling is also commonly used in the mining industry for over burden surveying. Such reverse circulation systems have historically employed low pressure drilling fluids and conventional drilling techniques. Yet, there are distinct advantages in using reverse circulation when fluids other than conventional borehole mud are pumped down the well bore especially for drilling deep well bores. Reverse circulation is an understood term of art in the drilling industry. When practiced with a single wall tubular drill pipe it comprises a reverse of the conventional "direct" circulation, or circulating the annular fluid down the annulus and up the inside of the drill pipe. When reverse circulation as practiced with dual wall tubular drill strings, concentric pipes, it consists of circulating the drill pipe annular fluid downward and balancing the hydrostatic head of the well bore annular fluid at a level to force the drill pipe annular fluid up the inner string of the drill pipe. The well bore annular fluid could be balanced in a static condition or maintained in a downwardly flowing condition by adjusting its density or by employing an artificially induced annular pressure using a rotating head on the blow out preventers at the surface. With this flow configuration the integrity of the borehole pressures may be controlled and stability maintained with conventional techniques, for which there is a wide scope of experience. Such experience engenders confidence and reliability. When a second fluid, whose physical properties are different than the conventional drilling mud, is injected into the borehole, problems may arise. If the second fluid is allowed to circulate in the borehole annulus, the confidence level of the drilling operators may be greatly reduced. There is simply not the same amount of experience with commingled fluids of varying physical properties in the borehole annulus and the same level of reliability is not found. Moreover, there are practical operational limitations in the effective rate of penetration using direct circulation, or flow up the borehole annulus. Due to laminar flow characteristics, typical in annular flow regions of direct circulation, the amount of cuttings which can be effectively suspended in the drilling mud and carried out of the well is limited. This is further aggravated by the dilutant effects of the second fluid commingled in the annulus. For these reasons, the reverse circulation turbulent flow regime has found select acceptance.
It would be a significant enhancement to utilize the advantages of reverse circulation and overcome the disadvantages of prior art drilling techniques by providing a reverse circulation fluid flow configuration with the advantages of high pressure jet drilling techniques. Summary of the Invention
The present invention pertains to methods of and apparatus for generating a borehole. More particularly, one aspect of the invention relates to a method of generating a borehole with dual concentric drill string of the type wherein a high pressure clarified fluid is pumped within the drill string through a tool adapted for high velocity jet cutting within the borehole. Drilling mud is placed within the borehole annulus for borehole stability. The improvement comprises the steps of pumping the high velocity fluid into the borehole and to the tool through an annulus in the dual concentric drill string and pumping the drilling mud into the borehole downwardly through the borehole annulus toward the tool. The drilling mud, high pressure clarified fluid, and cuttings are then returned up the borehole through the central conduit of the drill string.
In another aspect the methods and apparatus of the present invention utilize a concentric drill pipe string separately and in conjunction with a high pressure, minimally abrasive, drilling fluid which is circulated to a drilling tool through the annulus formed by the inner and outer concentric drill pipe walls. Various methods are employed to operationally perform the coring and/or drilling of a well bore. Although the present invention is set forth in connection with oil and gas well drilling, the principles and concepts embodied in the invention apply equally to other forms of drilling.
The present invention also comprises a drilling system for providing the basic working components for utilizing various down hole tools to perform coring, full hole drilling, hole opening, underreaming and specialized operations such as well testing and remedial work. In one preferred embodiment, the system includes a coring type drill bit attached to a combination drill string made up of two separate and independent drill strings which are coaxially arranged. The two coaxial drill strings are attached to a dual swivel arrangement that provides independent and/or coordinated rotational and reciprocal motion of the individual coaxial drill strings. The dual swivel system provides dynamic sealing between the drill strings allowing fluid to be pumped into the annulus formed between the outside wall of the inner drill string and inside wall of the outer drill string, as well as fluid circulation through the central bore of the inner drill string. Hoses are attached to the dual swivel arrangement and manifolded to allow for selectively changing the fluid sources and fluid circulation direction. The fluid manifold is connected to pumping equipment that draws fluid from a fluid processing system. The well bore includes a conventional blow out preventer system having a rotating head. Conventional choke and kill lines and manifolding are flow connected to the pumping system. This provides a supply of fluid to the well bore annulus ensure that the annulus fluid level is adequately maintained for well bore s abilization and pressure control during reverse circulation operations. In yet another aspect of the invention, the annular space, defined between the inner and outer drill strings, provides a conduit through which a high pressure drilling fluid is pumped to the drilling tool which, in the preferred embodiment, is a high pressure jet assisted mechanical core bit. The high pressure drilling fluid is ported through restrictions in the bit to accelerate the fluid jet to a velocity sufficient to erode the formation being drilled. Such fluid jet erosion of the formation tends to enhance the mechanical action of the core bit resulting in increased penetration rates and, thus, a reduction of the costs of drilling. The expended drilling fluid, the cored sections and the drilled cuttings are reverse circulated to the surface for processing. The inner bore of the coaxial drill string is used as the reverse circulation conduit through which the expended drilling fluids, the drilled cores and cuttings are removed from out of the well bore. The fluid handling system, to which the inner bore of the coaxial drill string is manifolded, is comprised of fluid processing and fluid delivery sub-system. The fluid processing system firstly incorporates a cyclone separator for cleaning the drilling returns generated in the reverse circulation coring mode. The larger drilled formation cores and fragments are conducted from the well bore through the inner drill string to the cyclone separator and are dynamically expelled therefrom. The more fluid returns, along with accompanying smaller formation fragments, are conducted to a conventional, mesh screened, shaker separator where the larger solids are removed. The clarified fluid is then conditioned as a recirculation source for both the high pressure and the more conventionally pressured fluid delivery systems. Since the high pressure drilling fluid should be of a minimally abrasive nature in order to avoid delivery equipment erosion, the source of such a minimally abrasive fluid can be derived from either an outside clear water source, such as a well, or, alternately, a portion of the processed return fluids could be additionally diluted, filtered, and/or run through a centrifuge and then pumped into the drilling system as the high pressure drilling fluid. The minimally abrasive, clarified drilling fluid is pumped through a high pressure pump into the rig standpipe manifold and thereby routed through the drilling swivel which ports the fluid into the coaxial drill string annulus for use at the drilling tool. Reconstituted conventional drilling mud is pumped into the borehole annulus to provide well bore stability and formation pressure control. Preferably only a small portion of the drilling mud will leak by the bit and thereby mingle with the clarified fluid. This can minimize the treatment costs of the reconstituted mud.
The system of the present invention also provides the benefits of high pressure fluid jet formation cutting in combination with reverse circulation fluid management. Various options may be used to circulate high pressure fluids in one or more of the concentric conduits, formed by the concentric tubes. The preferred embodiment provides more efficient circulation of well bore material from the hole, superior well bore information logging, safer well bore pressure control and superior well bore stability during drilling. In addition and of significant importance, it provides a meaningful increase in borehole penetration rate which enhances the over-all drilling economics in virtually all currently practiced drilling methods such as full bore drilling, coring, hole opening and underreaming. Another aspect of the present invention is its ability to independently manipulate the two concentric drill strings both rotationally and reciprocationally. The ability to independently manipulate the two conduits provides an apparatus for improved mechanical manipulation of down hole tools and the performance of other down hole operations, such as well testing or remedial work while safely circulating the well bore, oriented core retrieval, rotation or reciprocation of the drill bit with only one of the coaxial drill string, and rotation of a down hole pump by rotation of one of the coaxial drill strings. Brief Description of the Drawings
For a more detailed description of the construction and operation of the present invention, reference is now made to the following description taken in conjunction with the accompanying drawings, in which:
Fig. 1 is a schematic diagram of the general layout of the uphole and downhole equipment employed in one aspect of the system of the present invention;
Fig. 2 is a longitudinal cross-sectional view of part of a coaxial drill string used in the present invention showing the general direction of flow during the reverse circulation of fluids;
Figs. 3A-3C are partial longitudinal cross-sectional views of alternative designs for coupling and sealing the coaxial drill pipe used in the present invention, for which cross-sectional views are taken about the lines D-D, E-E and F-F, respectively of Figs. 3A-3C and illustrated therewith; Fig. 4A is a partially cut-away longitudinal cross- sectional view of the dual fluid, dual swivel system used in the present invention illustrating its general internal components; Fig. 4B is an alternative embodiment of the partially cut-away longitudinal cross-sectional view of the dual fluid, single swivel system of Fig. 4A;
Fig. 5A is a partial side plan view of the dual fluid, dual swivel system used in the present invention illustrating operation when a separate, two conduit, drill string with independent couplings is employed;
Fig. 5B is a partial side plan view of the dual fluid, dual swivel system used in the present invention illustrating operation when a two conduit drill string with an integral connection is employed; Figs . 6A- 6F are diagrammatic illustrations of various downhole operational modes illustrating both the present invention and a prior art embodiment;
Fig. 7 is an enlarged, perspective view of one embodiment of a drill bit adapted for use in accordance with the principles of the present invention;
Fig. 8 is an enlarged, side elevational, cross- sectional view of the drill bit of Fig. 7; and
Fig. 9 is an enlarged, side elevational, fragmentary cross-sectional view of the bit of Fig. 8.
Detailed Description of the Drawings
Referring first to Fig. 1 of the drawings, there is shown an illustrative schematic of the overall layout of the components of the system of the present invention. A formation cutting tool 1 for drilling through earthen formations is attached to the lower end of a dual conduit, coaxial or dual-concentric drill pipe 2. The cutting tool illustratively shown in the drawing is a drill bit for core drilling purposes. A plurality of length of drill pipe 2 are coupled to one another by couplings 3 to form a drill string. The drill pipe 2 forming the drill string is run into the well bore through a blowout preventer stack 4 having a rotating head 5 which combination serves to provide well pressure control means in the conventional manner. The upper end of the drill pipe 2 is flow connected to a first fluid swivel 6 which includes means with for rotationally and reciprocally sealing the annular space formed between the inner conduit 7 and the outer conduit of the coaxial drill string 2. The first fluid swivel 6 provides means for mechanically reciprocating and rotating the outer conduit of the coaxial drill pipe 2 independently of the inner conduit 7. The inner conduit 7 is attached to a second fluid swivel 8 which includes means for rotationally sealing the inner conduit of the coaxial drill string 2. The second fluid swivel 8 providing a mechanical means for mechanically reciprocating and rotating the inner conduit 7 in relation to the outer conduit of the drill string 2 and to the first fluid swivel 6.
A hose 10 is flow connected to the second fluid swivel
8 for conducting the drilled returns, in a reverse circulation operational mode, through flow line 11 to a cyclone separator 16 where the largest cuttings and core sections are centrifugically separated from the fluid and expelled through the lower section of separator 16. The drilled cores 40 are expelled from the bottom of the cyclone separator 16 into a core catcher 41 where they are collected for subsequent examination. Gases entrained in the liquid comprising the return flow are drawn from the cyclone separator by suction fan 46 and forced through gas vent riser 17. The resultant fluid of the return flow is passed out of the cyclone separator, through flow line 15 and into a screened vibrating separator means 29. The vibrating separator 29 screens the larger solid particles 35 from the returns liquid and deposits them into a fluid containment pit 26. The liquid portion 36 of the returns flow is collected in a holding tank 28.
The holding tank 28 is part of a fluid processing system in which the liquid returns are cleaned of drilled solids and reconditioned through the addition of various mud constituents and chemicals which enable a drilling mud to provide well bore stability and pressure control. Fluid is drawn out of the tank 28 through a suction pipe 38. The liquids passed through a centrifugally filtering means 30 to further clarify this portion of the return fluids and is then moved by flow line 33 into a storage tank 32 where it is held and further conditioned, if necessary, for use as a clarified high pressure jetting drilling fluid. An additional source of clarified fluid can also used to supply tank 32 and be derived from a non-closed system, such as from a water well 31 or by truck transportation.
Relatively clear, non-abrasive fluid is drawn from tank 32 through valve 42 and into suction line 21 by a charge pump (not shown). A high pressure pump 20 forces the high pressure fluid through flow line 19, high pressure hose 12 and into the first fluid swivel number 6. The high pressure fluid flow is connected into the annulus between the inner and outer conduits of the coaxial drill pipe 2 and conducted through the annulus to the drilling tool 1. High pressure pump 20 can also be connected to draw fluid directly from the fluid conditioning tank 28 through suction line 21. 12
This configuration is accomplished by closing valve 44, opening valve 43, and closing valve 42 thereby connecting the input of the flow line 21 to the conditioned fluid in holding tank 28 through flow line 34. Thus the operational setup of the equipment of Fig. 1 allows pump 20 access to either the clarified fluids that have been processed through the centrifugal filter system 30 and stored in tank 32 or to the fluid conditioning tank 28 directly. It should also be noted that the conditioned fluid contained within fluid holding tank 28 can also be drawn by pump 25 through flow line 34, valve 44, and flow line 27.
The pump 25 forces the conditioned fluid into flow line 47, through valve 24, flow line 23, hose 9 and into the blowout preventer system 4 where it is discharged into the well bore annulus 60 surrounding the drill pipe 2. The pump 25 can also draw either conditioned fluid from the fluid holding tank 28 or clarified fluid from the storage tank 32 and circulate that fluid into the central bore of inner conduit 7. This is accomplished by closing the valves 24 and 39 and opening the valve 18, and then flowing the conditioned fluid through lines 22 and 11, and through hose 10, second swivel 8 and into the central bore of the inner conduit 7.
Referring next to Fig. 2, there is shown a longitudinal cross section view of coaxial tubes forming the drill pipe 2 which are, in this embodiment comprised of two independent tubes 61 and 7. There is also shown the general direction of flow of the fluids during the reverse circulation mode of operation. Inner tubular conduit sections 62a and 62b are threadably connected end to end to form the inner conduit 7 portion of the drill pipe 2. Outer tubular conduit sections
61a and 61b are threadably connected end to end to form the outer conduit 61 of the drill pipe 2. A first annular space
64 is created between the outer wall of the inner conduit 7 and the inner wall of outer tube 61 forming the coaxial drill string 2. A second annular space 60 is created between the inside wall of the well bore through the formation and the outside wall of the drill string 2. The upper end of the borehole annulus 60 is in fluid communication with the interior of the blowout preventer stack 4 and fluid supply hose 9. Well casing 63 is disposed beneath the blowout preventer stack 4, which casing extends into the well bore as shown.
Clarified fluid from the high pressure pump 20 is delivered under high pressures which may be on the order of 20, 000 psi as an example, through lines 19 and 12 into the first swivel 6 (Fig. 1) which is connected to the coaxial annular space 64 for circulation of the fluid down to the drilling tool 1 at bottom of the hole (Fig. 1). It should be noted that other pressures may be used depending on the strength of the tubulars defining the high pressure annulus and the requisite pressure demands downhole. Conditioned fluid may be delivered by pump 25 through line 23 (Fig. 1), hose 9 and blow out preventer 4 for circulation down the well bore annulus 60 to the bottom of the hole. Both the clarified and the conditioned fluids are circulated back to the surface through the inner conduit 7.
Referring still to Fig. 2, several definitions must be understood for a complete discussion of the present invention.
The term "high pressure" as used herein refers to pressure substantially in the range of 3, 000 psi and higher. The term is used relative to the drilling tool and the annular flow region of the drill string as set forth and shown herein, which drilling tool and drilling string are disposed, in an operational mode, in a borehole. In that respect any pressure substantially higher than the pressure in the borehole annulus is contemplated by the term "high pressure" .
The term "high pressure annular flow region" as used herein refers to a flow region constructed to carry fluid pressure substantially in the range of 3,000 psi and higher. However, any fluid pressure in said annular flow region substantially higher than the pressure in the borehole annulus, which can produce a high velocity fluid jet is contemplated by the term "high pressure annular flow region" .
The term "high pressure drilling fluid" as used herein refers to a fluid adapted to be carried under pressure substantially in the range of 3, 000 psi and higher. The present invention teaches a dual-concentric drill string having a high pressure annular flow region formed therein through which high pressure drilling fluid may flow and any pressure of said fluid in said annular flow region substantially higher than the pressure in the borehole annulus is contemplated by the term "high pressure drilling fluid".
The term "high velocity fluid jet" is a conventional term in the drilling industry and refers to a fluid discharge stream capable of eroding subterranean formations such as rock to produce a kerf, or cut region, therein.
The high pressure annular flow region is provided by a dual-concentric drill string having a inner flow conduit of equal or greater pressure capacity to the outer drill pipe. The wall thicknesses of the respective tubular members are determined in accordance with the magnitude of fluid pressure therein, the fluid pressure differential across the wall section thereof, the tension or compression present in the tubular member and the torque transmitted thereby. Such conditions must be considered when determining the tube wall thicknesses as is conventional in the drilling industry. A suggested ratio of the wall thickness of central flow conduit 7 relative to the larger diameter conduit 61 may be on the order of 1 to 1.25 with the wall thickness of conduit 7 on the order of .3 inches or greater. This is submitted for purposes of illustration only, because the considerations of pressure, tension and torque for a specific application may result in a design configuration wherein the inner flow conduit 7 has a wall thickness substantially equal to the wall thickness of the outer drill pipe even though a higher pressure capacity is afforded in the inner conduit 7.
Referring now to Figs. 3A-3C there are shown partial longitudinal cross-sectional views of three different embodiments of dual conduit tubulars and interconnections between sections thereof that can be utilized in the present invention. The embodiment shown in Fig. 3A includes two separate conduits with one conduit 7 being coaxially arranged inside of the conduit 61. The inner conduit 7 is independently placed inside the outer conduit 61 to form the coaxial drill string 2. The inner conduit 7 may also be independently rotated and reciprocated apart from outer conduit 61. The outer conduit 61 may be a conventional oilfield tubular drill pipe section which is connected to an adjacent section by means of a conventional integrally formed tool joint 3. The upper most member 61a of conduit 61 and the lower member 61b of conduit 61 are threadably connected by threads 71. The tool joint connection 3 may include an elastomeric type of sealing mechanism 73 to provide either a primary or a secondary pressure seal. The combination of tool joint threads 71 and the pressure seal 73 enable the outer conduit 61 to transmit forces of both tension and torque while maintaining internal/external pressure containment. The upper member 62a of conduit 7 and the lower member 62b of conduit 7 are connected by means of threads 72. An elastomeric type of sealing member 74 provides an internal/external pressure seal. Cross section view DD, taken about the lines D-D of Fig. 3A illustrates the inner conduit 7 arranged coaxially with the outer conduit 61. Referring next to Fig. 3B, there is shown a second embodiment of a dual conduit, coaxial drill string 2 with the inner conduit 7 placed within the outer conduit 61. In this embodiment, the outer conduit 61 includes an upper member 61a and a lower member 61b both being comprised of external drill pipe sections which are connected by a tool joint 3. The tool joint 3 is comprised of an upper member 82 and a lower member 83. The upper tool joint member 82 threadedly connected to the end of the upper outer conduit member 61a to provide an upper section of the outer conduit 61. The lower tool joint member 83 is threadedly connected to the end of the lower outer conduit member 61b. Tool joint members 82 and 83 are threadably connected to one another by means of threads 71 and sealed together by sealing member 73. The lower tool joint member 83 contains an inner conduit retainer 76, which is held within the member 83 by engagement of the lower outer conduit member 61b. The retainer 76 threadably engages the lower member 62b of inner conduit 7 by means of threads 80. The retainer 76 also includes sealing members 75 which provide peripheral seals for the upper member 62a of inner conduit 7 when it is inserted into the retainer 76. The retainer 76 provides the ability to maintain adequate sealing of conduit 7 while it dynamically reacts to the forces of pressure, temperature, tension and torque exerted upon the dual conduit system through pressure induced expansion and contraction and/or tension induced stretch of the outer conduit 61 of the drill string 2. The retainer 76 is permanently installed and has a low profile cross section to allow maximum fluid flow through the tool joint 3 with minimal fluid pressure drop thereacrosε.
Referring now to Fig. 3C, there is shown a third embodiment of a dual conduit coaxial drill string 2 comprised of the inner conduit 7 and the outer conduit 61.
The outer conduit 61 consists of an upper member 61a and a lower member 61b threadably connected through an integrally formed tool joint connection 3 containing threads 71. The inner conduit 7 is comprised of a lower conduit 62b and an upper conduit 62a. The lower conduit 62b is threadedly connected to a retainer 77 which is held in position within the lower member 61b by a threaded retainer ring 78 containing sealing threads. The retainer ring 78 also contains a sealing member 73, which provides an internal/external pressure seal for the tool joint connection 3. The retainer 77 contains circular sealing members 75 which provide peripheral sealing for the upper conduit 62a as it is inserted into the retainer 77 thereby forcing the member 75 into sealing engagement against the prepared outer surface 74 on the upper end of the conduit 62a. The lower conduit 62b is connected to retainer 77 by means of threads 80. This third embodiment allows the inner conduit 7 to be removed under field conditions by removing retainer ring 78 and retainer 77 to effect repairs on the inner conduit 7 or to utilize the external drill pipe 61 as a single conduit drill stem.
Fig. 3 drawings DD, EE and FF illustrate the top plan, cross-sectional views of the drill strings of 3A-3C, respectively, taken across lines DD, EE and FF respectively. The structure of each is apparent from the drawing. Referring next to Fig. 4A, there is shown a partially cut-away longitudinal cross section view of the dual-conduit dual fluid swivel system used in the system of the present invention. The system actually includes two separate fluid swivels, 6 and 8 which operate independently of one another yet in tandem with the dual conduit drill string 2. The first swivel 6 is comprised of two motors 104A and 104B along with drive assemblies 103A and 103B and a driving gear 102 which is attached to a first swivel sub 101. The swivel sub 101 is in turn threadedly attached to the outer conduit of the coaxial drill pipe string 2 and is supported by a rotary bearing 108 mounted within the housing 109. A plurality of seals 105, 106, and 107A provide sealing integrity for the fluid cavity 100 and allow sealed rotational motion of the swivel sub 101 while fluid is being circulated from line 12 into the cavity 100 and down the annulus between the outer wall of the inner conduit 7 and the inner wall of the swivel sub 101 which is connected to the dual conduit drill string 2. The seal 107 allows both reciprocating and rotational motion of the inner conduit 7 without leakage of the fluid being pumped into cavity 100.
The housing 109 is supported by the drilling rig travelling hoist equipment (not shown) which allows raising and lowering of the luid swivel 6.
The inner conduit 7 is attached to a second swivel sub 96 which is supported by a bearing package 92 mounted within housing 112. The swivel sub 96 is rotated by a gear 94 which is driven by gears 93A and 93B which are in turn driven by motors 97A and 97B. A pair of seals 98 and 91 provide a sealing means which allows rotation of the swivel sub 96 within the housing 112 while fluids are being circulated through line 10. The housing 112 of the second swivel 8 is supported by the drilling rig travelling hoist equipment (not shown) to provide independent raising and lowering of the housing 109 of the second swivel 8 separate from the housing 109 of the first swivel 6.
Referring now to Fig. 4B, there is shown a partial cut away longitudinal cross-sectional view of a dual-conduit dual fluid swivel that would be used in conjunction with an integral joint dual-conduit drill string. The system actually represents the previously described fluid swivel 6 (Fig. 4A) with the modification being incorporated predominantly to provide allowance for the inner conduit 7 to fit within a modified seal housing HOB and additionally attaching hose 10 to the upper portion of the seal housing. Modifications of the seal housing include the inclusion of radial bearing 113 and seal 107B which provides a means with which to radially align and position inner conduit 7 allowing effective sealing by seal 107B. The cited modifications in Fig. 4B now allow inner conduit 7 to be flow connected to hose 10 completing the ability of the swivel to handle dual fluids. Referring now to Figs. 5A and 5B there are shown, respectively, side views of two different operational modes for the fluid swivels 6 and 8. Fig. 5A illustrates the first swivel 6 and the second swivel 8, operating in conjunction with the independent dual-concentric tubular drill string 2 shown in Fig. 3A in which the inner conduit 7 can be rotated and reciprocated independently from the outer conduit of the drill string 2 thereby providing one set of operational capabilities. Thus, as illustrated in Fig. 5A, the first swivel 6 and the second swivel 8 are independent of one another with reference to relative rotational and reciprocal motion. Fig. 5B illustrates the configuration of the first swivel 6 and the second swivel 8 when they are used in conjunction with an integrally connected dual-concentric drill pipe string 2 as shown in Figs. 3B and 3C. The conduit inter connections illustrated in Figs. 3B and 3C do not allow independent rotation or reciprocation of the inner conduit 7 with respect to the outer conduit of the dual- concentric drill string 2. This operational configuration provides a different set of functional capabilities. Thus, as illustrated in Fig. 5B, the first swivel 6 and the second swivel 8 are restricted from relative movement by the attachment of swivel 8 to swivel 6 by means of a retainer clamp 114.
Referring now to Fig. 6, Fig. 6A illustrates a dual- concentric drill string 2 with a single annular high pressure jet drilling fluid flow being used for a core drilling operation. The arrangement is employing reverse circulation and the well bore annulus contains surface injected well bore stabilizing and pressure control fluid 300. As illustrated in the method of Fig. 6A, a high pressure annular drilling fluid 301 is forced down the annular space 64 between the inner and outer conduits of the coaxial drill pipe 2 and jetted through the tool 1 to assist in coring the formation. Any annular flow between the inner wall of the well bore and the outer wall of the drill string 2 wall is reverse circulated back up the central bore 303 of the inner conduit 7 along with the cores and/or large chip cuttings and the expended drilling fluid as return fluid 305.
Fig. 6B illustrates a prior art dual-concentric drill string flowing high pressure drilling fluid with full bore drilling using high pressure fluid jetting techniques. A low pressure well bore stabilizing and pressure control fluid 601 is circulated in direct circulation downwardly through a low pressure annulus 603. The method illustrated in Fig. 6B includes pumping high pressure drilling fluid 605 downwardly through the drill string central conduit 607 and jetting the fluid through the drill bit 609 to assist in cutting the formation in a full face cut. (See U. S. Patent No. 4,624,327) The fluid 601 (drilling mud) is pumped through the annulus 603 and also discharged through the drill bit as shown. The fluids and the cuttings are then return circulated up the annular space 611 between the inner wall of the well bore and the outer wall of the drill pipe string 2. One of the problems with this approach is effectively removing the cuttings with the commingled fluids in the annulus. Both laminar flow problems and variations in well bore fluid properties can impede drilling techniques using this approach. Moreover, the uncertainties surrounding the use of commingled fluids in such an environment can seriously inhibit its effectiveness.
Fig. 6C illustrates a dual-concentric drill string 2 flowing an annular high pressure drilling fluid flow which is concurrently used for both core drilling and hole opening functions in conjunction with reverse circulation. The method illustrated in Fig. 6C includes pumping a high pressure annular drilling fluid 301 through the annulus between the outer wall of the inner conduit 7 and the inner wall of the outer conduit of the coaxial drill string 2. The flow is divided between a fixed blade hole opener 212 and a drill bit 214 in order to pilot drill and hole open the formation in a single pass. An alternative to this method is to pump a high pressure annular drilling fluid down the annulus between the inner and outer coaxial tubes of the drill string 2 into a fixed blade hole opener which is used to open the hole of an already drilled pilot hole as described further in Fig. 6F. Fluid 300 is also pumped downwardly between the inside wall of the well bore and the outside wall of coaxial drill string 2 and reverse circulated as return fluid 305 back up the inner bore 303 of the inner conduit 7, along with the drilled cores and large chip cuttings.
Fig. 6D illustrates a dual-concentric drill string 2 with an annular high pressure drilling fluid 301 being utilized for both concurrent core drilling and well bore underreaming functions in conjunction with reverse circulation. The method illustrated in Fig. 6D includes a high pressure drilling fluid 301 being pumped between the coaxial conduits of the drilling string 2 into an expandable arm underreamer 310 and into the tool 1 to cut the formation. An alterative of this method is to pump a high pressure annular drilling fluid down the annulus between the coaxial conduits of the drill string 2 into an expandable arm underreamer to underream the hole of an already drilled pilot hole. Fluid is pumped between the outer wall of the well bore and the outer wall of the coaxial drill pipe 2 to flow downward to the bottom of the hole and reverse circulate up with drilled cores and large chip cuttings.
Fig. 6E illustrates a dual-concentric drill string 2 conducting an annular high pressure drilling fluid 301 being utilized for high pressure fluid jetting during a backreaming operation. A reverse circulated well bore stabilizing and pressure control fluid 300 (drilling mud) is pumped down the borehole annulus 60 in a reverse circulation path. The method illustrated in Fig. 6E is for underreaming in which a high pressure drilling fluid flow is also pumped downwardly between the coaxial conduits of the drill string 2 into an expandable arm underreamer 312. The arms of the underreamer expand to provide a cutting face that is directed upwardly. As the arms of the underreamer expand, the drill pipe 2 is rotated and hoisted towards the surface in a backreaming method. The drilling mud is returned back to the surface through the inner bore 303 of the conduit 7 as return fluid 305. Fig. 6F illustrates a dual-concentric drill string 2 conducting an annular high pressure drilling fluid flow being utilized for hole opening of an existing well bore in conjunction with reverse circulation. The method illustrated in Fig. 6F includes pumping a high pressure drilling fluid 301 down between the inner conduit and outer conduit of the coaxial drill string 2 into a hole opener 314 having a cutting face 316 directed downwardly and outwardly. Flow of drilling mud 300 in the annular space 60 between the well bore wall and drill string 2 is downward and reverse circulated back to the surface through the central bore 303 of the conduit 7. The drill pipe 2 is rotated and lowered downwardly from the surface in a hole opening method.
Referring now to Fig. 7, there is shown a large perspective view of one embodiment of a drill bit 200 adapted for use in accordance with the principles of the present invention. The drill bit 200 is secured to the end of the dual-concentric drill string 202, different embodiments of which have been described above. The drill bit 200 comprises a cylindrical body 206 having a plurality of slots 204 formed along the cylindrical side walls thereof. The slots 204 are of the type commonly referred to as "junk slots" in the industry. The junk slots 204 extend across the drilling end, or face 208 of the drill bit 200 to form recessed regions 210. The junk slots 204 then extend into the mouth 212 and the throat of the drill bit 200 as shown in the drawings. A plurality of fluid discharge ports or orifices 214 may be seen to be disposed about the body, face and mouth of the drill bit 200. A fluid discharge port 216 is, for example, disposed outwardly along taper, or chamfer area 218. Chamfer area 218 comprises a transition region between the generally cylindrical body 206 and the face 208 of the drill bit 200. Likewise, fluid discharge ports 220 are disposed in the mouth 212 at select positions and orientations as hereinafter described. The discharge of the high velocity, clarified fluid, in accordance with the principles of the present invention, is illustrated through the lines 222 emanating from each fluid port 214. The fluid discharge is specifically adapted for cutting the subterranean formation as described above and is further illustrated below.
Referring now to Fig. 8, there is shown an enlarged, side elevational, cross-sectional view of the drill bit 200 and the subterranean formation 230. The formation 230 is depicted with a diagrammatical kerf pattern 232 which illustrates the one select pattern of cutting produced by the fluid jets 214 of Fig. 7. A plurality of kerfs 234 are thus seen extending into the formation 230 adjacent a surface 236 comprising the outline of the subterranean formation 230 adjacent the drill bit 200. In actual use the flow of fluids in the grinding, breaking and crunching action of the drill bit would produce a variety of earthen configurations as described in more detail below. What is shown herein is the drill bit 200 in a diagrammatical illustration of the effect of the discharge jets 222 and the cutting action produced thereby. Consistent therewith, the drill bit itself is shown with an outer cylindrical housing 202 in which a series of internal flow passages 242 are disposed at one end in flow communication with each of the fluid discharge orifices 214. At the other end, not shown in this view, the passage 242 are provided in sealed flow communication with the high pressure flow annulus of the drill string discussed above. A central bore 244 disposed centrally within face 208 (Fig. 7) is adapted for the flow of subterranean formation cuttings and drilling fluids upwardly therethrough and is provided in flow communication with a central flow passageway 246 in flow communication with the drill pipe 202 coupled thereto. A diagrammatic illustration of one embodiment of a fluid discharge orifice 250 is likewise shown for purposes of illustration. Various fluid discharge orifices adapted for jet drilling could be used in conjunction with the present invention and the present description is provided for purposes of illustration only. Referring now to Fig. 9, there is shown an enlarged side elevation, fragmentary cross-sectional view of the bit of Fig. 8 illustrating the result of mechanical movement therewith. As described above, the bit 200 is rotated in conjunction with the discharge of fluid through jet orifices 214. The junk slots engage the surface 236 and impart mechanical forces to the subterranean formation around kerfs 234. The kerfs 234 weaken this region of the formation resulting in fractures. Sections 270 of the formation 230 are thus shown to be fractured and broken as will result by the rotation of the bit 200 as said bit engages the weakened section 230 in which kerfs 234 are selectively formed. As weakened sections are disposed between the rotating junk slot 204 they are broken off into chunks 270. The chunks 270 then migrate under the pressure of the fluids discharged from the jets 214 upwardly into bore 244 and subsequently into conduit 246 for flow upwardly within the dual- concentric drill pipe as described above.
In operation, the present invention provides improved drilling efficiency and economics by the utilization of high pressure jet drilling techniques in conjunction with reverse flow circulation. The jet bit configuration as described herein produces such a high penetration rate that the cuttings are most efficiently removed up the central annulus. This has a dual benefit. The first advantage is the fact that the central flow maintains support of the cuttings in a cylindrically confined, turbulent flow environment not plagued by the cuttings carrying capacity limitations of the laminar flow necessary in the annular return environment of direct circulation. A much higher volume of cuttings can be carried up the central return conduit in view of this flow configuration thus effectively removing any penetration rate constraint such as is present in the flow regimes required for annular flow. Secondly, the drilling mud viscosity and resultant integrity of the borehole annulus is not compromised by the infiltration of a second fluid of different viscosity and flow characteristics. Moreover, the central conduit requires less volume to more effectively remove the large volume of drilled cuttings generated by the teachings of the present invention and there is little borehole fluid actually circulating through the system which results in minimal fluid velocities in the borehole annulus and less treatment requirements. This also promotes better borehole wall stability and therefore greater well bore integrity. Conventional mud for well bore stability and well pressure control can thus be utilized with a drilling technique which is directed toward a very different, high penetration rate drilling method. The myriad of drilling styles which are discussed above further emphasize the variety of drilling techniques which can be incorporated with the present invention.
It is thus believed that the operation and construction of the present invention will be apparent from the foregoing description. While the method and apparatus shown or described has been characterized as being preferred it will be obvious that various changes and modifications may be made therein without departing from the spirit and scope of the invention as defined in the following claims.

Claims

Cl aims
1. An improved method of drilling a borehole of a type wherein a well bore is produced in a subterranean formation with a drill bit disposed at the end of drill pipe passing through the well bore to define a first annulus therearound, including means for establishing a circulation of drilling fluid into said first annulus, the improvement comprising the steps of: providing a dual-concentric drill pipe having a central flow conduit disposed within a larger diameter pipe and adapted for defining a second, high pressure, annular flow region therearound; providing said drill bit in flow communication with said second, high pressure, annular flow region and in a configuration adapted for producing a high velocity fluid jet for the cutting of the well bore; providing means for rotating said drill bit adjacent said formation for generating cuttings therefrom; circulating high pressure drilling fluid within said second, high pressure annulus for discharge from said drill bit as said fluid jet; returning said high pressure drilling fluid through said central conduit; and providing drilling fluid in said first annulus outwardly of said drill pipe and flowing said fluid downwardly and forcing said high pressure drilling fluid to return through said central conduit.
2. The method as set forth in claim 1 and including the step of flowing drilling fluid around said drill bit and up said central conduit during said drilling operation, and flowing a greater quantity of high pressure fluid discharged as said fluid flows through said return central conduit.
3. The method as set forth in claim 1 and including the step of joining said dual-concentric tubes through dual- concentric couplings to permit the downward flow of high pressure drilling fluid through said second annulus and the upward flow of high pressure drilling fluid and cuttings through the central flow conduit.
4. The method as set forth in claim 3 and including the step of positioning said central flow conduit in independent axial relationship relative to said outer drill pipe and permitting relative axial movement therebetween.
5. The method as set forth in claim 1 and further including the step of providing a filtration system for said high pressure fluid and said drilling fluid and the step of filtering said fluids for reσirσulation within the borehole.
6. The method as set forth in claim 1 and further including the step of providing said dual-concentric drill pipe in a configuration wherein the ratio of the wall thickness of said central flow conduit relative to said larger diameter drill pipe is on the order of 1: 1.25.
7. The method as set forth in claim 6 and further including the step of providing said central flow conduit with a wall thickness at least on the order of 0.3 inches.
8. The method as set forth in claim 1 and further including the step of providing a plurality of fluid jetting ports about the face of said drill bit, discharging said high pressure fluid from said ports while rotating said drill bit and increasing the depth of the well bore.
9. The method as set forth in claim 1 and further including the steps of disposing a plurality of fluid jetting ports laterally about said drill bit, discharging said high pressure fluid from said ports while rotating said drill bit and increasing the size of the well bore.
10. An improved method of drilling a borehole with a dual- concentric drill string having a central conduit and positioned in the borehole of the type wherein high pressure clarified fluid is pumped within the drill string through a downhole tool adapted for high velocity jet cutting within the borehole, the improvement comprising the steps of: forming a high pressure flow annulus within said dual-concentric drill string; securing said downhole tool to the end of said drill string in flow communication with said high pressure flow annulus;
pumping the high pressure clarified fluid into the borehole and through said downhole tool through said high pressure annulus of said drill string; pumping said drilling mud into the borehole through reverse circulation downwardly through said borehole annulus around said drill string to the downhole tool; and returning the drilling mud, high pressure clarified fluid and cuttings through the central conduit of the drill string.
11. The method as set forth in claim 10 and further including the step of providing said dual-concentric drill string in a configuration having a central flow conduit disposed within a larger diameter drill pipe defining said drill string annulus.
12. The method as set forth in claim 11 and further including the step of positioning said central flow conduit in independent axial relationship relative to said drill pipe and permitting relative axial movement therebetween.
13. The method as set forth in claim 10 wherein said step of securing said downhole tool to the drill string includes the steps of providing a drill bit having a plurality of fluid jetting ports disposed thereon, securing said drill bit in flow communication with said drill string annulus and discharging said high pressure clarified fluid from said fluid jetting ports.
14. The method as set forth in claim 13 and further including the step of providing means for rotating said drill bit while discharging said high pressure clarified fluid from said fluid jetting ports.
15. The method as set forth in claim 14 and including the step of providing a plurality of fluid jetting ports about said drill bit face, discharging said high pressure fluid from said ports of said face while rotating said drill bit, and increasing the depth of the borehole through the cutting action of said fluid jetting ports and said rotation.
16. The method as set forth in claim 10 wherein said step of securing said downhole tool to the drill string includes the steps of providing a borehole diameter enlarging tool having a plurality of fluid jetting ports disposed therearound, securing said tool in flow communication with said drill string annulus, and discharging said high pressure clarified fluid from said fluid jetting ports.
17. The method as set forth in claim 16 and further including the step of providing means for rotating said tool while discharging said high pressure clarified fluid from said fluid jetting ports.
18. The method as set forth in claim 17 and including the step of providing a plurality of fluid jetting ports laterally spaced around said tool, discharging said high pressure fluid from said laterally spaced ports while rotating said tool and increasing the diameter of the borehole through the cutting action of said fluid jetting ports and said rotation.
19. The method as set forth in claim 16 and further including the step of providing a slim hole drill bit for said downhole tool, producing an exploration borehole with said slim hole drill bit, replacing said drill bit with said enlarging tool for enlarging said exploration hole and expanding said exploration hole for purposes of opening said hole for recovery of matter disposed within the subterranean formation accessed by said borehole.
20. Improved apparatus for generating a borehole of the type wherein a downhole tool is carried at the lower end of a drill string for cutting said borehole in a subterranean formation, said tool including means for producing a high velocity fluid jet and mechanical motion for cutting said formation, a first borehole fluid present within the annulus of the borehole and a second borehole fluid present within the drill string for discharge through the jets to impart formation cutting therefrom, the improvement comprising: a dual-concentric drill pipe having a central flow conduit adapted for reverse circulation of fluid upwardly therethrough and an annulus adapted for high pressure fluid flow downwardly therearound; means for pumping to said tool said second fluid under high pressure in said annulus of said dual-concentric drill string; and means for circulating said first borehole fluid downwardly through said borehole annulus to the tool and upwardly through the central conduit thereof along with said second fluid discharged from said jets and the cuttings therefrom.
21. The apparatus as set forth in claim 20 wherein the ratio of the wall thickness of said central flow conduit relative to said larger diameter drill pipe is on the order of 1: 1.25.
22. The apparatus as set forth in claim 21 wherein said central flow conduit has a wall thickness at least on the order of 0.3 inches.
23. The apparatus as set forth in claim 20 wherein said downhole tool comprises a drill bit having a plurality of fluid jetting ports disposed about the face of said drill bit, said ports being adapted for discharging said second fluid while said bit is rotating for increasing the depth of the borehole.
24. The apparatus as set forth in claim 20 wherein said downhole tool comprises a borehole diameter enlarging tool having a plurality of fluid jetting ports disposed laterally about said tool, said ports being adapted for discharging said second fluid while said tool is rotating for increasing the size of the borehole.
25. A method for drilling a borehole in subterranean formation utilizing a first drilling fluid while maintaining a second, high density fluid in the borehole annulus, said method comprising: pumping said second, high density fluid downwardly through the borehole annulus; disposing a dual-concentric drill string within the borehole annulus, said drill string having a central flow conduit and an annulus formed therearound; disposing a slim hole drill bit at the end of said dual-concentric drill string, said bit adapted for producing a high velocity fluid jet and mechanical motion; pumping said first drilling fluid down through said annulus of said dual-concentric drill string through said bit; cutting said subterranean formation in the borehole with said first drilling fluid; breaking said cut subterranean formation with mechanical movement from said bit; and returning said first and second fluids and said broken formation cuttings within said borehole upwardly through said central flow conduit of said dual-concentric drill string to said well head.
26. The method as set forth in claim 25 further including the step of providing means for filtering said fluids and the step of removing said cuttings from said fluids for recirculation within said borehole.
27. The method as set forth in claim 25 further including the step of producing an exploration borehole with said slim hole drill bit, providing a drill bit adapted for enlarging said exploration hole and expanding said exploration hole for purposes of opening said hole for recovery of matter disposed within the subterranean formation accessed by said borehole.
PCT/US1991/002874 1990-04-27 1991-04-26 Method and apparatus for drilling and coring WO1991017339A1 (en)

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WO1995033119A1 (en) * 1994-05-27 1995-12-07 Eric Clifford Braumann Drilling apparatus
WO1996018800A1 (en) * 1994-12-15 1996-06-20 Telejet Technologies, Inc. Method and apparatus for drilling with high-pressure, reduced solid content liquid
AU682966B2 (en) * 1994-05-27 1997-10-23 Eric Clifford Braumann Drilling apparatus
EP1957744A1 (en) * 2005-11-21 2008-08-20 Luc De Boer Method for varying the density of drilling fluids in deep water oil and gas drilling applications
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CN105551362A (en) * 2015-12-24 2016-05-04 中国地质大学(武汉) Horizontal directional drilling annular rock debris migration integration simulation experiment method and experiment apparatus thereof

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WO2011076848A1 (en) * 2009-12-23 2011-06-30 Shell Internationale Research Maatschappij B.V. Determining a property of a formation material
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AU682966B2 (en) * 1994-05-27 1997-10-23 Eric Clifford Braumann Drilling apparatus
WO1995033119A1 (en) * 1994-05-27 1995-12-07 Eric Clifford Braumann Drilling apparatus
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WO2013184100A1 (en) * 2012-06-05 2013-12-12 Halliburton Energy Services, Inc. Methods and systems for performance of subterranean operations using dual string pipes
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US9856706B2 (en) 2012-06-05 2018-01-02 Halliburton Energy Services, Inc. Methods and systems for performance of subterranean operations using dual string pipes
CN105551362A (en) * 2015-12-24 2016-05-04 中国地质大学(武汉) Horizontal directional drilling annular rock debris migration integration simulation experiment method and experiment apparatus thereof

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