US3675728A - Slim hole drilling - Google Patents

Slim hole drilling Download PDF

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US3675728A
US3675728A US3675728DA US3675728A US 3675728 A US3675728 A US 3675728A US 3675728D A US3675728D A US 3675728DA US 3675728 A US3675728 A US 3675728A
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Prior art keywords
drill
diameter
string
tool
pipe
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Joseph H Faulk
Lloyd R Kern
Graham E King
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Atlantic Richfield Co
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Atlantic Richfield Co
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    • 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
    • E21B17/00Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods ; Cables; Casings; Tubings
    • E21B17/10Wear protectors; Centralising devices, e.g. stabilisers
    • E21B17/1078Stabilisers or centralisers for casing, tubing or drill pipes
    • 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

Abstract

A method and apparatus for employing slim hole drilling techniques and avoiding key seat problems, particularly when moving a drill string into or out of the wellbore.

Description

United States Patent Faulk et al.

[15] 3,675,728 [4 1 July 11,1972

[54] SLIM HOLE DRILLING [72] Inventors: Joseph H. Foulk, Dallas; Lhyd R. Kern, Irving; Graham E. Ki, Dallas, all of Tex.

[73] Assignee: Athnflc Rlchfleld Company, New York,

[22] Filed: Sept. 18, I970 [21] Appl.No.: 73,405

[52] U.S.Cl. ..l75/57, 175/325, 308/4A [51] Inl. E211) 17/00 [58] Field of Search ..l75/57, 61, 325; 308/4 A References Cited UNITED STATES PATENTS 2,079,449 5/1937 Haldeman ..175/325 Examiner-James A. Leppink Attorney-Blucher S. Tharp and Roderick W. MacDonald [57] ABSTRACT A method and apparatus for employing slim hole drilling techniques and avoiding key seat problems, particularly when a drill string into or out of the wellbore.

12 Chin, 7 Drawing Figures II: ....n... i

V 3 I g M F? INVENTORS Joseph H. Foulk Loyd R. Kern Graham E. King MM ATTORNEY PKTE'N'TEDJUL 1 1 1972 SHEET 10F 3 PKTE'N'TEDJUL 1 1 1912 3. 675,728

SHEET 2 0F 3 Fig. 3

lo ,6 I i 1 6 so Q I j/ -\Q\ Hg. 7 Fig. 5

INVENTORS Joseph H.Foulk Loyd R. Kern Graham E' King ATTORNEY P'A'TENTEUJULH I972 3,675,728

SHEET 30F 3 Fig. 8

INVENTORS 1 Joseph H. Foulk Loyd R. Kern Graham EhKing BYW ATTORNEY BACKGROUND OF THE INVENTION I-Ieretofore in drilling wellbores drill strings have been made up of a plurality of sections of drill pipe. Adjacent ends of the drill pipe sections were joined together by a device normally referred to as a tool joint. A tool joint can be either a separate coupling means into which is threaded both adjacent ends of the two sections of drill pipe, a device where one adjacent end of the drill pipe has an internally threaded box member into which threads the other adjacent end or pin end of the drill pipe, and the like. Tool joints normally are of larger diameter than the pipe to which they are attached. In any event, tool joints are the device by which two adjacent sections of drill pipe are joined one to another in a drill string. Therefore, a drill string normally has a substantial number of tool joints at spaced apart points along the length thereof. At the bottom of the drill string is the drill bit and adjacent to the bit in the drill string there is normally employed at least one drill collar.

The outside diameter of the bit is normally the largest crosssectionally dimensioned member of the drill string because it determines the diameter of the wellbore throufli which all of the rest of the members of the drill string must pass.

Drill collars are provided so as to impose weight on the bit to improve its drilling rate. These collars are therefore large heavy members which closely approach the cross-sectional dimensions of the bit and wellbore. If the drill collar is a square or spirally grooved device its largest cross-sectional dimension will be substantially that of the drill bit and wellbore because with these configurations there are passageways between the wellbore side and the drill collar which allow movement of drilling fluid thereby. If the drill collar is round it will normally be of an outer cross-sectional diameter slightly less than that of the drill bit or borehole to allow an annulus for the passage of drilling fluid thereby. In any event, the drill collars are large diameter members which closely approach, if they are not substantially the same as, the outside diameter of the bit.

The tool joints, on the other hand, being only devices for connecting adjacent sections of pipe, need not be and are not as large as the drill collars or bit and therefore are of substantially smaller diameter than the bit or collars.

The pipe, tool joints, and collars could all be of the same outside diameter. This situation is quite disadvantageous however in that it necessitates thicker walled pipe in order to equal the outer diameter of the tool joints and collars and this in turn substantially reduces the space for fluid flow in the annulus between the drill string and wellbore, substantially increases the weight and cost of the pipe, and eliminates the abovementioned-tool joint shoulder that is so useful in connection with In slim hole drilling very small diameter wellbores, i.e., no

larger than about 6 inches in diameter, are drilled using extremely high, at least about 500 rpm, preferably from about 600 to about 2,000 rpm, rotation rates for the drill string. Because of the extremely high rotation rates in the very small diameter wellbore, the drill string strikes the side of the wellbore more often during drilling than in conventional rotary drilling. At least two factors that contribute to the greater frequency of contact between the drill string and the side of the wellbore are the high rate of rotation of the drill string causing lateral vibration of the drill string and the high rate of rotation of the drill string causing more turns of the drill string per foot of drilling depth, e.g., 10 to 20 times the rate of rotation as compared to conventional rotary drilling with three times as fast a drilling rate.

Therefore, in slim hole drilling there is an exceedingly greater propensity to the formation of key seats. Key seats are fonned by the drill string and drill string tool joints bearing against a side of the wellbore and wearing a groove or side hole into the side of the wellbore.

Accordingly, it is very important in successful slim hole drilling to either avoid the formation of key seats or to have available a device or method which renders key seats that may be rendered unobtrusive to subsequent drilling steps such as removing the drill string from the wellbore to replace a worn out bit and then re-entering the wellbore with the drill string.

In the normal situation where the pipe is of smaller outside diameter than the tool joint there is provided a shoulder where, in effect, the pipe expands out to the tool joint diarneter. This shoulder is useful for conventional smooth wall rig elevators to abut against when lifling the pipe into or out of the hole.

the smooth wall rig elevators. In this situation slip type elevators must be used on the pipe and with the pipe being heavier than normal and the like, the slip elevators are more prone to allow the pipe to slide while gripped by the elevators than when smooth wall elevators are used abutting a tool joint shoulder. These elevators have dies which cut into the pipe weakening it and making it more prone to fatigue type failures. Another system for pulling the flush joint pipe, e.g., to change bits, involves the use of lift plugs or lift nipples threaded into each stand of drill pipe to permit engagement of appropriate elevators. This system is ineflicient because of the excessive time required to install these devices when pulling the pipe and to remove them when rerunning the pipe into the hole to recommence drilling or to perform other operations.

SUMMARY OF THE INVENTION According to this invention, it has been found that in slim hole drilling, the problems associated with the formation of key seats can be avoided even though the key seats may be formed by employing tool joints which have an outside diameter at least as large as the largest cross-sectional dimension of the drill collar employed and no larger than the outside diameter of the drill bit.

It has further been found that the formation of key seats can be reduced by employing stabilizers and/or pipe protectors along the length of the drill string so that these elements contact the side of the wellbore before the tool joints. These elements are provided with abradable outer surfaces so that their surface wears away in preference to the side of the wellbore.

Accordingly, an object of this invention is to provide a new and improved method for avoiding the problems encountered with the formation of key seats. It is another object to provide a new and improved apparatus which avoids the problems of key seats after they are formed. It is another object to provide a new and improved method and apparatus for avoiding the formation of key seats during slim hole drilling. It is another object to provide a new and improved method and apparatus for rendering key seats innocuous.

Other aspects, objects and advantages of this invention will be apparent to those skilled in the art from this disclosure and the appended claims.

DETAILED DESCRIPTION OF THE INVENTION FIG. 1 shows a conventional drill string.

FIG. 2 shows the conventional drill string as it is drilling a wellbore and how key seats are formed thereby.

FIG. 3 shows a cross-sectional view of a keyseat.

FIG. 4 shows how key seats can be a problem upon removal of the drill string from the wellbore.

FIG. 5 shows a stabilizer means on a drill string.

FIG. 6 shows a cross-sectional view of the stabilizer means of FIG. 5.

FIG. 7 shows a pipe protection means on a drill string.

FIG. 8 shows a drill string with tool joints having an outside diameter at least as large as the drill collars.

More specifically, FIG. 1 shows drill bit 1 with a square drill collar 2 adjacent thereto and a round drill collar 3 adjacent to drill collar 2, the bit and collars being supported by a section of drill pipe 4. Pipe 4 is joined to an adjacent section of drill pipe 5 by a tool joint 6. Collar 3 is joined to pipe 4 by tool joint 30. Tool joints 6 and 30 are shown as a coupling which is a separate member that is internally threaded so that for example the adjacent ends of pipe sections 4 and 5 can be threaded into opposite ends of coupling 6 thereby mechanically joining pipes 5 and 6.

This sequence of joining adjacent sections of pipe by a tool joint is repeated for as long a length as desired for the drill string. Normally, there is a tool joint about every 30 feet in a drill string and therefore with wellbores of depths of 5,000 to 20,000 or more feet there will be a substantial number of tool joints at spaced apart points along the length of the drill string. This is shown in FIG. 2.

Heretofore the relative diameters of the elements were as shown in FIG. 1, i.e., dn'll collars 2 and 3 being of about the same diameter as bit 1 and tool joints 6 and 30 being of substantially smaller diameter than collars 2 and 3 and bit 1.

FIG. 2 shows a vertical cross section of a wellbore l drilled in the earth 1 1 with the drill string in the wellbore. It should be noted that FIG. 2 is not drawn to scale in that the angle of deviation of wellbore 10 is exaggerated in order to more clearly show the mechanism by which a key seat is formed and in that the length of drill collars 2 and 3 is not shown in proper proportion in relation to the drill bit, drill pipe sections and the like. However, these variances will be obvious to one skilled in the art and are done so the better to represent how a key seat is formed.

Since no'wellbore is exactly vertical and therefore deviates some to one side of perpendicular as shown in an exaggerated manner in FIG. 2, a portion of the drill string such as that represented by drill pipe sections 12, 13 and 14 joined tool joints 15 and 16, will come into contact with the side of the wellbore during drilling. Since contact is made during drilling, the drill string being rotated at a very high rate, a side hole 24 will actually be dug into the side of the wellbore. The side hole has a diameter 21 (FIG. 3) of thatof the tool joints'lS and 16. Since the tool joints have a diameter less than that of bit 1 side hole 24 will have a diameter less-than that of bit 1 and the wellbore.

This is represented in FIG. 3 which shows the cross-sectional diameter of wellbore as compared to the cross-sectional diameter 21 of side hole 24 after being formed by tool joints 15 and 16. Depending upon the conditions of drilling and the particular formations at which the tool joints 15 and 16 come in contact with the side of the wellbore, the side hole 24 can have a depth 22which is less than, equal to, or greater than the diameter of the drill pipe and/or tool joints.

Referring back to FIG. 2, it is often the case that there are adjacent formations of different strength characteristics pierced by wellbore 10 and at which a key seat is formed. The adjacent formations can be, for example, a coherent formation 17 which maintains the diameter of the wellbore on its own (e.g.,' a sandy formation) and which overlays a less coherent formation 18 which does not retain the diameter of the wellbore (e.g., a shale whose clay content is dispersed by the drilling fluid or vibrationally removed by the drill string, and the like). In such a situation there will be formed a cavity 19 in the shale formation 18 below the more coherent sand formation 17. This set of circumstances causes a problem when removing the drill string from the wellbore as is shown in FIG. 4.

FIG. 4 shows that as the drill string is pulled upwardly for removal from wellbore 10, drill collar 3, being of a diameter greater than tool joint 30, will become wedged against formation 17 at about point 31 since collar 3 is of greater diameter than tool joint 30 and therefore of greater diameter than diameter 21 of side hole 24. The drill string thus becomes hung up in the hole and can not readily be pulled from the wellbore.

According to this invention such problems are avoided in that in a slim hole drilling method comprising rotary drilling a wellbore having a diameter no greater than about 6 inches, preferably from about 2 to about 5 inches, and rotating the drill pipe and its tool joints at a rate of at least about 500 rpm, an additional step is used of employing tools joints which have an outside diameterat least as large as the largest cross-sectional dimension of drill collars 2 and 3 but no larger than the outside diameter 20 of bit 1.

The tenn largest cross-sectional dimension" is employed so as to apply to round, square, spirally grooved, or any other configuration of drill collar or tool joint conventionally used. When the drill collar is round the largest cross-sectional dimension is the outside diameter of the drill collar. When the drill collar is square, the largest cross-sectional dimension is that dimension which extends from one comer of the square to the other corner of the square and will normally be substantially the same as the outside diameter 20 of bit 1.

The apparatus used according to this invention will comprise a drill string of at least two sections of drill pipe joined by at least one tool joint, a bit at one end of the string and at least one drill collar in the string adjacent to the bit, the tool joints in the string having an outside diameter at least as large as the largest cross-sectional dimension of the collar or collars present but no larger than the outside diameter of the bit.

By following the teachings of this invention, the largest dimension 21 of side hole 24 of the key seat will be at least as large as the largest cross-sectional dimension of collars 2 and 3. Therefore, these collars can readily be pulled through side hole 24 without hanging up at 31 in FIG. 4.

The largest diameter 21 of side hole 24 can be .of a dimension smaller than that of the outside diameter 20 of bit 1 because the drill bit is at the end of the drill string and has been found to be sufiiciently free to move under the influence of gravity to drag on the lower side 23 of wellbore 10 when being removed therefrom thereby avoiding contact with side hole 24 of the key seat.

The above description relates to that portion of this invention which reduces the problems encountered when key seats are formed. As an aid in preventing the formation of key seats in the first place, the drill string can have at spaced apart points along the length thereof a stabilizer means and/or pipe protection means which helps keep the drill string from contacting the side of the wellbore in the first place and which abrades away when it contacts the side of the wellbore so that the stabilizer means or pipe protection means preferentially I wears away rather than forming a key seat in the wall of the wellbore.

Heretofore stabilizers have been run near the bottom of the drill string to help keep the wellbore vertical. By this invention stabilizers and/or pipe protectors as hereinafter disclosed are employed at spaced apart points along the length of the drill string to help avoid the formation of key seats.

FIG. 5 shows a rotatable stabilizer 40 mounted on a drill pipe section 41 below tool joint 42. One or more stabilizers 40 can be mounted on each or any desired section of drill pipe in a drill string.

As shown in FIG. 6, stabilizer 40 is composed of four spaced apart rubber bearings 50 which bear upon drill pipe 41 and which are supported by a steel sleeve 51. Around the circumference of sleeve 51 is a rubber member 52 which has a plurality of rubber projections 53 which extend substantially out to the inner wall of wellbore l0.

Bearings 50 can be a single rubber cylinder with grooves therein to admit lubricating fluid. Nonabradable sleeve 51 must be of a diameter less than the tool joint diameter or else it can become stuck in a key seat in the same manner as a larger diameter drill collar.

When stabilizer 40 comes in contact with the wellbore elements 53 come in contact with the wellbore wall and member 52, sleeve 51, and bearings 50 rotate about drill pipe 41. If any abrading is accomplished in this encounter the loss is that of elements 53 and not of a portion of the wall of wellbore 10. The spaces 54 between bearings 50 are to allow access of drilling fluid to act as lubricant for bearings 50. Bearings 50 can be connected through sleeve 51 to element 52 for example by having continuity of rubber from bearings 50 through spaced apart apertures (not shown) in sleeve 51 to rubber in element 52.

FIG. 7 shows substantially the same apparatus as that of FIG. 5 except that pipe protection means 60 has been substituted for stabilizer means 40. Here again one or more prm tection means 60 can be carried by any or each section of drill pipe along the length of the drill string.

Protection means 60 is composed of a rubber sleeve having a passageway 61 therethrough. Passageway 61 is of a diameter slightly smaller than the outer diameter of drill pipe 41 so that the protection means, when stretched to slide over drill pipe 41, will snugly grip the outside of pipe 41. The outer diameter of protection means 60 is slightly larger than the diameter of the tool joints so that when the drill string moves towards a side of the wellbore an outer surface of protection means 60 touches the wellbore first and will be abraded away before tool joint 42 touches the wellbore side.

Any nonabradable element of stabilizer 40 and protector 60 must have an outer diameter less than that of the tool joints to avoid sticking in a key seat.

Of course, in some circumstances stabilizer 40 and protector 60 may be abraded away to an extent where tool joint 42 can contact the side of wellbore 10. In this situation it is important that the sizing of the tool joints with respect to the nonabradable parts of 40 and 60, the drill collars, and the bit be according to this invention as described hereinbefore. In this manner, even if a side hole is formed after abrasion away of members 40 and 60, the drill string can still be removed from the wellbore because the side hole diameter 21 will be larger than the diameter or largest cross-sectional dimension of drill collars 3 and 2, respectively.

The abradable material on stabilizer 40 and protector 60 can be any material which will be worn away in preference to the side of the wellbore and, although rubber is presently preferred, can be any of a large number of possible materials including plastics, such as polypropylene, polypropalene, nylon, teflon, and the like, malleable metals such as lead or metal alloys, and the like. The abradable portion of stabilizer 40 and protector 60 is also of value in case the drill string becomes hung up in the wellbore in that it can be sheared off without causing the failure of a tool joint or other necessary part of the drill string thereby freeing the drill string for movement.

FIG. 8 shows a bit 60 connected to round drill collar 61. The remainder of the drill string is composed of drill pipe sections such as 63 and 65 joined by tool joints such as 62 and 64, the tool joints having an outside diameter at least as large as the outside diameter of drill collar 61.

EXAMPLE An oil well was drilled in the Bob K Field of Cooke County, Texas to a total depth of 4,180 feet using a drill string composed of elements substantially as that shown in FIG. 2. The wellbore was drilled with a diamond bit having an outside diameter of 3 iltinches. The drill string was composed of drill pipe sections 2 1/16 inches in outside diameter joined by 2 %inch outside diameter coupling tool joints and having a round 2 %inch diameter drill collar mounted above a 3 riiinch outside diameter spirally grooved drill collar, the spirally grooved drill collar being adjacent to the diamond bit. The wellbore had a deviation from vertical of 2 maximum.

Upon attempting to pull this drill string from the wellbore starting with the bit at a depth of 2,847 feet in the wellbore, the drill string became hung up in a key seat as was determined by results while carrying out a fishing operation and later confirmed by running a wireline caliper tool. The drill string hung up a plurality of times in a single trip out of the wellbore.

For comparison purposes, substantially the same drill string was thereafter employed in the same wellbore except that the drill collars used had a maximum cross-sectional dimension or diameter of 2 iiiinches. When running this drill string no drill string sticking was encountered upon its removal from the wellbore starting with the bit at a depth of 4, l 80 feet.

Reasonable variations and modifications are possible within the scope of this disclosure without departing from the spirit and scope of this invention.

The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:

1. A slim hole drilling method comprising rotary drilling a wellbore having a diameter no greater than about 6 inches, rotating the drill pipe and its tool joints at a rate of at least about 500 rpm, and employing at least one drill collar adjacent the drill bit, said tool joints having an outside diameter at least as large as the largest cross-sectional dimension of said at least one drill collar but no larger than the outside diameter of said drill bit.

2. A method according to claim 1 wherein said wellbore diameter is from about 2 to about 5 inches and said rotation rate is from about 600 to about 2,000 rpm.

3. A method according to claim 1 wherein there is employed a plurality of rotatable stabilizers at spaced apart points along the length of the drill pipe and/or drill collars, the stabilizers having at least an external portion which is composed of an abradable material and which has an outside diameter at least as large as the outside diameter of said tool joints but no greater than the diameter of said bit, all nonabradable parts of said stabilizers being of an outside diameter less than the outside diameter of said tool joints.

4. A method according to claim 3 wherein said abradable material is rubber.

5. A method according to claim 1 wherein there is employed a plurality of pipe protectors at spaced apart points along the length of the drill pipe, said protectors having at least an external portion which is composed of an abradable material and has an outside diameter at least as large as the outside diameter of said tool joints but no greater than the diameter of said bit, all nonabradable parts of said stabilizers being of an outside diameter less than the outside diameter of said tool joints.

6. A method according to claim 5 wherein said abradable material is rubber.

7. A slim hole drill string for drilling wellbores having a diameter no greater than about 6 inches, comprising at least two sections of drill pipe joined by at least one tool joint, a drill bit at one end of said drill string, at least one drill collar in said drill string adjacent said drill bit, said at least one tool joint having an outside diameter at least as large as the largest cross-sectional dimension of said at least one drill collar but no larger than the outside diameter of said drill bit.

8. An apparatus according to claim 7 wherein there is a plurality of rotatable stabilizer means at spaced apart points along said drill string, said stabilizer means having at least an external portion which is composed of an abradable material and which has an outside diameter at least as large as the outside diameter of said at least one tool joint but no greater than the diameter of said bit, all nonabradable parts of said protector means being of an outside diameter lesS than the outside diameter of said at least one tool joint.

9. An apparatus according to claim 8 wherein said abradable material is rubber.

10. An apparatus according to claim 7 wherein there is a plurality of pipe protector means at spaced apart points along said drill string, said protector means having at least an external portion which is composed of an abradable material and has an outside diameter at least as large as the outside diameter of said at least one tool joint but no greater than the diameter of said bit, all nonabradable parts of said protector means being of an outside diameter less than the outside diameter of said at least one tool joint.

11. An apparatus according to claim 10 wherein said abradable material is rubber.

12. An apparatus according to claim 10 wherein there is a plurality of rotatable stabilizer means and pipe protector means at spaced apart points along the length of said drill string.

t t i i

Claims (12)

1. A slim hole drilling method comprising rotary drilling a wellbore having a diameter no greater than about 6 inches, rotating the drill pipe and its tool joints at a rate of at least about 500 rpm, and employing at least one drill collar adjacent the drill bit, said tool joints having an outside diameter at least as large as the largest cross-sectional dimension of said at least one drill collar but no larger than the outside diameter of said drill bit.
2. A method according to claim 1 wherein said wellbore diameter is from about 2 to about 5 inches and said rotation rate is from about 600 to about 2,000 rpm.
3. A method according to claim 1 wherein there is employed a plurality of rotatable stabilizers at spaced apart points along the length of the drill pipe and/or drill collars, the stabilizers having at least an external portion which is composed of an abradable material and which has an outside diameter at least as large as the outside diameter of said tool joints but no greater than the diameter of said bit, all nonabradable parts of said stabilizers being of an outside diameter less than the outside diameter of said tool joints.
4. A method according to claim 3 wherein said abradable material is rubber.
5. A method according to claim 1 wherein there is employed a plurality of pipe protectors at spaced apart points along the length of the drill pipe, said protectors having at least an external portion which is composed of an abradable material and has an outside diameter at least as large as the outside diameter of said tool joints but no greater than the diameter of said bit, all nonabradable parts of said stabilizers being of an outside diameter less than the outside diameter of said tool joints.
6. A method according to claim 5 wherein said abradable material Is rubber.
7. A slim hole drill string for drilling wellbores having a diameter no greater than about 6 inches, comprising at least two sections of drill pipe joined by at least one tool joint, a drill bit at one end of said drill string, at least one drill collar in said drill string adjacent said drill bit, said at least one tool joint having an outside diameter at least as large as the largest cross-sectional dimension of said at least one drill collar but no larger than the outside diameter of said drill bit.
8. An apparatus according to claim 7 wherein there is a plurality of rotatable stabilizer means at spaced apart points along said drill string, said stabilizer means having at least an external portion which is composed of an abradable material and which has an outside diameter at least as large as the outside diameter of said at least one tool joint but no greater than the diameter of said bit, all nonabradable parts of said protector means being of an outside diameter less than the outside diameter of said at least one tool joint.
9. An apparatus according to claim 8 wherein said abradable material is rubber.
10. An apparatus according to claim 7 wherein there is a plurality of pipe protector means at spaced apart points along said drill string, said protector means having at least an external portion which is composed of an abradable material and has an outside diameter at least as large as the outside diameter of said at least one tool joint but no greater than the diameter of said bit, all nonabradable parts of said protector means being of an outside diameter less than the outside diameter of said at least one tool joint.
11. An apparatus according to claim 10 wherein said abradable material is rubber.
12. An apparatus according to claim 10 wherein there is a plurality of rotatable stabilizer means and pipe protector means at spaced apart points along the length of said drill string.
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US5379843A (en) * 1992-10-22 1995-01-10 Shell Oil Company Side-tracking cement plug
US5423379A (en) * 1989-12-27 1995-06-13 Shell Oil Company Solidification of water based muds
US5673753A (en) * 1989-12-27 1997-10-07 Shell Oil Company Solidification of water based muds
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US6250405B1 (en) 1999-01-06 2001-06-26 Western Well Tool, Inc. Drill pipe protector assembly
US6739415B2 (en) 1999-01-06 2004-05-25 Western Well Tool, Inc. Drill pipe protector
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US3799279A (en) * 1972-09-25 1974-03-26 R Farris Optionally stabilized drilling tool
US5673753A (en) * 1989-12-27 1997-10-07 Shell Oil Company Solidification of water based muds
US5423379A (en) * 1989-12-27 1995-06-13 Shell Oil Company Solidification of water based muds
US5277519A (en) * 1992-10-22 1994-01-11 Shell Oil Company Well drilling cuttings disposal
US5284513A (en) * 1992-10-22 1994-02-08 Shell Oil Co Cement slurry and cement compositions
US5285679A (en) * 1992-10-22 1994-02-15 Shell Oil Company Quantification of blast furnace slag in a slurry
US5301752A (en) * 1992-10-22 1994-04-12 Shell Oil Company Drilling and cementing with phosphate-blast furnace slag
US5301754A (en) * 1992-10-22 1994-04-12 Shell Oil Company Wellbore cementing with ionomer-blast furnace slag system
US5307876A (en) * 1992-10-22 1994-05-03 Shell Oil Company Method to cement a wellbore in the presence of carbon dioxide
US5307877A (en) * 1992-10-22 1994-05-03 Shell Oil Company Wellbore sealing with two-component ionomeric system
US5309997A (en) * 1992-10-22 1994-05-10 Shell Oil Company Well fluid for in-situ borehole repair
US5309999A (en) * 1992-10-22 1994-05-10 Shell Oil Company Cement slurry composition and method to cement wellbore casings in salt formations
US5311944A (en) * 1992-10-22 1994-05-17 Shell Oil Company Blast furnace slag blend in cement
US5275511A (en) * 1992-10-22 1994-01-04 Shell Oil Company Method for installation of piles in offshore locations
US5314031A (en) * 1992-10-22 1994-05-24 Shell Oil Company Directional drilling plug
US5314022A (en) * 1992-10-22 1994-05-24 Shell Oil Company Dilution of drilling fluid in forming cement slurries
US5322124A (en) * 1992-10-22 1994-06-21 Shell Oil Company Squeeze cementing
US5325922A (en) * 1992-10-22 1994-07-05 Shell Oil Company Restoring lost circulation
US5269632A (en) * 1992-10-22 1993-12-14 Shell Oil Company Method for strengthening the structural base of offshore structures
US5343950A (en) * 1992-10-22 1994-09-06 Shell Oil Company Drilling and cementing extended reach boreholes
US5343951A (en) * 1992-10-22 1994-09-06 Shell Oil Company Drilling and cementing slim hole wells
US5343952A (en) * 1992-10-22 1994-09-06 Shell Oil Company Cement plug for well abandonment
US5343947A (en) * 1992-10-22 1994-09-06 Shell Oil Company Anchor plug for open hole test tools
US5351759A (en) * 1992-10-22 1994-10-04 Shell Oil Company Slag-cement displacement by direct fluid contact
US5358049A (en) * 1992-10-22 1994-10-25 Shell Oil Company Conversion of emulsion mud to cement
US5379843A (en) * 1992-10-22 1995-01-10 Shell Oil Company Side-tracking cement plug
US5311945A (en) * 1992-10-22 1994-05-17 Shell Oil Company Drilling and cementing with phosphate
US5332040A (en) * 1992-10-22 1994-07-26 Shell Oil Company Process to cement a casing in a wellbore
US5833019A (en) * 1996-11-27 1998-11-10 Pegasus International Inc. Pipe protector
US5833018A (en) * 1996-12-20 1998-11-10 Pegasus International Inc. Drill pipe/casing protector
US6250405B1 (en) 1999-01-06 2001-06-26 Western Well Tool, Inc. Drill pipe protector assembly
US6378633B1 (en) 1999-01-06 2002-04-30 Western Well Tool, Inc. Drill pipe protector assembly
US6739415B2 (en) 1999-01-06 2004-05-25 Western Well Tool, Inc. Drill pipe protector
US20040188147A1 (en) * 1999-01-06 2004-09-30 Western Well Tool, Inc. Drill pipe protector
US7055631B2 (en) 1999-01-06 2006-06-06 Western Well Tool, Inc Drill pipe protector
US20150233182A1 (en) * 2014-02-14 2015-08-20 Baker Hughes Incorporated Downhole Depth Measurement Using Tilted Ribs
US9488006B2 (en) * 2014-02-14 2016-11-08 Baker Hughes Incorporated Downhole depth measurement using tilted ribs

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CA945136A (en) 1974-04-09 grant

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